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Abstract Stringent environmental regulations and higher costs of effluent treatments in oil and gas process industries have necessitated research into ways to improve the operating procedures in effluent treatment plant. In Gas-to-liquid (GTL) plant, a significant quantity of reaction water is produced and various chemicals are used as intermediate treatment chemicals. The reaction water is contaminated by these chemicals which impair the pH and the related properties of the water. The pH has to be controlled before the water is re-used or released to the environment. A laboratory-scale effluent neutralization unit for pH control was designed and built to demonstrate the feasibility of utilising produced carbon dioxide (CO2) from reforming reactions in both the synthesis and hydrogen production units in GTL plant for insitu effluent treatment. At the end of the reaction, the total volume of carbon dioxide used was recorded. This paper presents experimental neutralisation characteristics for different operating conditions. The prime advantage of this process can be thought to be less expensive than other published carbon capture and storage (CCS) processes. Moreover the carbon dioxide does not require further compression, dehydration and storage facilities before usage. Pipeline transportation is also drastically reduced since the captured carbon dioxide is utilised within the plant. This study demonstrated that, the neutralisation time increased by 3.15 minutes with increase in effluent volume from 40 to 60 litres and by 10.4 minutes as the temperature increased from 20oC to 50oC. The increase in the flow rate of carbon dioxide from 15 litres/min to 35 litres/min decreased the neutralization time from 19.15 minutes to 13.32 minutes. Finally it was estimated that about 64% of the daily carbon dioxide production which would have otherwise been emitted to the atmosphere was used in the treatment process. Introduction The fact that the concentrations of carbon dioxide in the atmosphere are increasing is known to environmentalists, researchers and government agencies. The causes of global change lie in the industrial activities of human society and ultimately in the population growth and increase in resource use by man. Human activities have increased carbon dioxide concentrations from approximately 280 to 355ppm since 1800 (Vitousek, 1994). This increase is likely to have climatic consequences on biota in all earth's terrestrial ecosystems. The need to reduce global climate change due to emission of carbon dioxide (CO2) and other greenhouse gases has led to research in carbon capture and sequestration (CCS). Several relatively small-scale carbon capture and sequestration approaches are currently in development and demonstration stages as highlighted by Hoekman, 2010. Direct injection into the oceans has also been suggested but there are a number of uncertainties over the ecological impact and equilibrium of the gas with the atmosphere. In the medium term, depleted oil and gas reserves, unmineable coal seams, and deep saline formations are the best options for carbon dioxide storage. Deep saline formations appear to offer the potential to store several hundreds of years' worth of carbon dioxide emissions. This must be validated, and site selection criteria must be developed and shared internationally to identify the most appropriate storage sites. Wider international collaboration and consensus are critically needed to ensure the viability, availability and permanence of carbon dioxide storage. However carbon capture and sequestration faces both technical and economic challenges. Therefore, there is the need to explore other methods to deal with carbon dioxide emissions. Transformation to chemical feedstock like methanol is a commercially proven technology, however carbon dioxide captured from flue gas from furnaces will not be economical for this purpose because of its low pressure. Recompression is required before the carbon dioxide could be processed to methanol (Ritter et al, 2007). Another well-known process - the Sabatier reaction, converts carbon dioxide to methane as shown in Eq. (1).

Abstract Anaerobic microorganisms which are frequently associated with corrosion fail Control of bacterial activity are posing major challenge in Saudi Arabia's massive seawater flooding systems. Biocides are used to control bacteria throughout the oil industry. A study to explore the feasibility to develop a detection technique for biocide batch treatments, preferably on-line and in real time, for their potential use in seawater flooding system network is described. Several methods to measure key components of the biocide composition were investigated in the initial stage. Three different techniques were explored during the feasibility phase study to detect and measure concentrations of biocide in seawater. This helped our plans for designing a sensor based on such detection techniques. The techniques explored were to monitor change in temperature, change in pH, and change in chromophore concentration (colorimetric) in the enzymatic reaction. The investigated methods included the use of acetylcholine esterase, based on the pH change as a result of acetate formation, the production of reaction heat (thermal) or on the colorimetric detection of the chromophore concentration based on the conversion of acetylthiocholine in combination with a chromophore. It was found that the colorimetric system was the most versatile system to perform the measurement to be able to show the feasibility of the method in real sea water samples and to demonstrate the effects of the biocides on the measurement system. 1.0 Introduction In water flooding systems, deoxygenated and filtered seawater is injected at strategic points along the periphery of the oil reservoir, displacing the oil and "pushing" it toward oil supply wells in the center of the formation. The technique enhances crude oil recovery substantially and allows for greater returns from the field. The seawater flooding system in Saudi Arabia is the largest of its kind in the world. It is deoxygenated water and treated with various organic biocides mixtures. The short duration, high concentration batch biocide treatment is designed to prevent the growth of bacteria in the system, thereby minimizing biofouling, water quality deterioration and Microbially Influenced Corrosion (MIC). Since the system's size is massive, it is very challenging to detect the arrival of a biocide slug treatment at the far water injection wells. Furthermore, quantification of biocide residual concentration in 'real time' at remote desert locations is not currently possible. Developing sensor technologies, which will quantify biocide residual concentrations hundreds of kilometers from the biocide injection location without manual sample collection and conventional wet chemistry analysis, is challenging.

Abstract Adding partially hydrolyzed polyacrylamide (HPAM) to flood water for enhanced oil recovery has resulted in some difficulties for treatment and re-injection of produced water at Daqing Oilfield of China: Production of the injected HPAM increased water phase viscosity and emulsification of the produced fluid, leading to more oil carry-over; The state-of-art cationic water clarifiers showed poor compatibility with HPAM containing produced water due to formation of very sticky oily flocs which seriously pollutes bed filters and slop oil recovered in produced water treatment. Throughputs of existent produced water treatment facilities had to be lowered by up to 50% so that the HPAM containing produced water might be treated to re-injection specifications. As an alternative for the state-of-art cationic water clarifier, a nonionic reverse demulsifier and demulsifier consisting of both water soluble and oil soluble active components respectively for water clarification and water-in-oil emulsion breaking, was developed as a water dispersible micro-emulsion mixture. Injected into high water-cut o/w produced fluid prior to the initial oil/water separation, the dual function chemical greatly enhanced flocculation and coalescence of the oil droplets in the reverse crude oil emulsion while maintaining adequate emulsion breaking capability for downstream crude oil dehydration, leading to less oil carry-over and looser emulsion in the influent water of produced water treatment facilities. In one field application, injected at a dosage of 15mg/L into the polymer flooding produced reverse crude oil emulsion upstream of oil/water separation, the dual function chemical reduced the oil content in the influent water of a produced water treatment facility from 2004mg/L to 443mg/L, and lowered the oil content in the effluent water of bed filters from 31mg/L to 4.1mg/L without application of water clarifiers.

Abstract Under the laboratory simulation of HTHP reservoir (65?, 11MPa), the indigenous microorganisms in Z3 Block of Sinopec Shengli Oilfield were activated selectively; the total number of bacteria, the surface tension of aqueous solution, the change of oil viscosity and the consumption of activating nutrient during activating were tested. Then, the physical simulation experiments of indigenous microbial flooding were performed. According to the main mechanism of IMEOR, the mathematical model reflecting the metabolism, growth and reproduction of indigenous microorganisms, the migration of component and the change of fluid properties was established. Using the orthogonal design method, the program optimization and economic evaluation involving three parameters of activating nutrient concentration, air injection quantity and injection PV were carried on. Then according to the actual situation of oilfield, the optimal program was proposed and the numerical simulation of Z3 Block was performed. The lab results show that taking the corn syrup powder (carbon source, best concentration 0.3%) and (NH4)2HPO4 (nitrogen and phosphorus source, best concentration 0.3%) as the main activating nutrient, the microorganisms can be activated successfully. Under the condition of optimal activating nutrient concentration, the total number of bacteria is above 2×108 cell/mL after 12 days; the surface tension of bacterial liquid reduces only a little; the oil viscosity reduces by 15% and the corn syrup powder concentration reduces from 0.3% to 0.05% about 15 days. Core flooding experiments indicate that the indigenous microorganisms can enhance oil recovery about 8.5% after water flooding. The program optimization results show that the optimal program is that the concentration of activating nutrient is 0.7%, the liquid-gas ratio of air injection is 1:12 and the injection PV is 0.3PV. According to the actual and optimization results, the optimal program suitable for oilfield is as follows: the total nutrient injecting slug is 0.3PV (6 years) with in each cycle (20 days), injecting the activating nutrient for 1 day and the rest 19 days, injecting water and air. The forecasting enhanced oil recovery is 5.97%, increasing oil 16.84×104t. Introduction At present, many oilfields in the world have entered the high water-cut time, facing the problems of quick production decline, big difficulty of stable production and low recovery. Therefore, how to enhance oil recovery further becomes a question urgently to be solved currently. As a new tertiary recovery technology, compared with other technologies, MEOR (microbial enhanced oil recovery) especially IMEOR (indigenous microbial enhanced oil recovery) has many advantages. It can adjust to the reservoir better, its cost is lower with simple equipment and construction and it does not pollute the environment and damage the reservoir and thus, it has a good application prospect (Cheng et al., 2006). Now, large-scale application of this technology has been reported in Russia, Russia, Norway and so on and obtained better effect (Awan et al., 2006). In China, it has been applied in Oilfields of Daqing, Shengli, Dagang, Xinjiang and so on, and achieved significant effect of water decreasing and oil increasing (Cheng et al., 2005; Chen et al., 2006; Zhang et al., 2008). However, the MEOR mechanism and numerical simulation software need to be performed further.

The pdf file of this paper is in Russian. The English version of this paper, IPTC-17269-MS, was presented at theInternational Petroleum Technology Conference held 19–22 January, 2014, in Doha, Qatar. Abstract With a step out distance of 170 km and a design power of 55MW, Martin Linge offshore gas field, will be the longest AC submarine cable power supplying an entire offshore Oil and Gas platform from the shore. This field development comprises a platform with a jack up rig and a Floating Storage Offloading unit. This paper discusses the criteria to consider and select a power from shore concept instead of an offshore Gas Turbine power plant which is the current practice in the offshore Oil and Gas industry. Since in a first approach, for such long step-out distance, the choice of power from shore would be to select a DC transmission line, the paper discusses the design and the main technical challenges of this long step-out AC transmission development. Finally, the system approach, required for the development of the onshore and offshore part of the project, is described. Introduction Discovered in 1975, Martin Linge offshore gas field (formerly named Hild) and located in the North Sea will be operated by Total Norge which has chosen to base this development with a power from shore concept. The facility will be designed for remote control from Total Norge onshore base in Stavanger (Norway). The field will be developed with a subsea installation and topside facilities. The processed gas will be exported to Total St Fergus terminal in UK via a new link to the existing Frigg UK Pipeline (FUKA). The oil, water and condensates will be processed and stored on a dedicated FSO storage vessel where water will be separated for reinjection, and oil will be exported via shuttle tankers. With a step out distance of 161km and a design power of 55MW, this will be the world's longest AC submarine cable power supplying an entire offshore Oil and Gas platform from the shore. This paper discusses the criteria which have been considered to select a power from shore concept instead of an offshore Gas Turbine power plant which is the current practice in the offshore Oil and Gas industry. Since in a first approach, for such long step-out distance, the choice of power from shore would be to select a DC transmission line, the paper discusses also the design and the main technical challenges of this long step-out AC transmission development. Finally, the paper underlines the electrical design particularities of this development and gives an operator's viewpoint as to the way forward. Project presentation The Martin Linge Field (formerly named Hild), is located on the Norwegian Continental Shelf, 75 km North of Frigg, 42 km West of Oseberg, 87 km North-East of Bruce, and 38 km South-East of Alwyn North field. TOTAL E&P Norge is the operator (49%) with Petoro (30%) and Statoil (21%) as partners. The Martin Linge field is one of the largest un-developed gas discoveries in the North Sea. Discovered 30 years ago, and operated today by Total E&P Norge AS, the field consists of several faulted and segmented gas condensate accumulations in the mid-Jurassic Brent group. The field also includes the Frigg oil reservoir which is a viscous, thin oil accumulation overlain by a small gas cap. Production is expected to be ~ 100 kboepd peak after start-up in quarter 2016, with ~ 70 kboepd during gas plateau. The total reserves are expected to be 176 Mboe. The production drive mechanism for the Hild (Brent) wells will be pressure depletion, i.e. no injection wells are planned for reservoir pressure maintenance. Frigg oil wells will be artificially lifted with gas lift. The produced water will be re-injected into the Frigg reservoir aquifer (not needed for pressure support).

Abstract Wellbore fluid flow profiles in both producers and injectors tend to change over time due to preferential depletion, formation damage, cross-flow, channelling or tubing or casing leaks. These changes can result in excess water production through channelling, coning, non-uniform water breakthrough (fingering) or out-of-zone injection – all leading to uneven flow, pressure and sweep profiles. Ignoring these complications can result in missing key points on reservoir behaviour, selecting wrong units for a 3D full-field flow model or misleading redevelopment planning. Therefore, it would be logical to check for changes in flow geometry before embarking on costly workovers, recompletion or infill drilling programs. This paper compares and integrates the results of conventional Production Logging Tool (PLT) surveys that use spinners and multiphase sensors with those acquired by reservoir-oriented production logging surveys employing a combination of Spectral Noise Logging (SNL) [1,2] and High Precision Temperature (HPT) Logging [3–5]. PLT and HPT-SNL produce similar results when wellbore and completion conditions are good but they may differ dramatically in cases of non-uniform formation damage, channelling behind pipe or plugging of perforations by scale. Generally, HPT-SNL would assess the flow geometry and invaded zones of the reservoir while PLT would point out where fluid enters or leaves the wellbore or tubing. The paper provides case studies from a mature offshore waterflooded field producing a mix of oil, gas, formation water and injection seawater, which complicates the identification of flow geometry and invasion zones and represents a challenge for reservoir engineers in developing proper drilling or workover programmes to target residual reserves [6, 7]. The HPT-SNL-PNL surveys and further studies described here led to successful workovers and drilling. The redevelopment results can be easily assessed by decline curve analysis. Introduction Since 2007, Dubai Petroleum Establishment (DPE) has performed more than 150 integrated PLT-HPT-SNL surveys to monitor vertical wellbore injection and production profiles that resulted in valuable and often surprising findings including unexpected water breakthrough intervals, bypassed oil zones and layers and water channelling behind casing in producers and injectors. These findings, in turn, led to a better understanding of how water propagated through reservoir from injectors to producers and were used to calibrate a 3D full-field flow model and identify optimum infill drilling locations for the redevelopment of the highly fractured crestal area of the field.

Abstract A large number of oil and gas fields in the Peninsular Malaysia basin are screened (masked) by shallow gas, resulting in wipe out zones of the underlying seismic amplitudes as well as push down and time delay (sag) of the structural closure of economical oil or gas fields. Such effects lead to significant uncertainties in resolving and mapping of the objective reservoir units below the shallow gas. On these premises, 3D 4C Ocean Bottom Cable (OBC) seismic survey has been acquired and processed in one of the gas and oil fields in the Malay basin with the objective of resolving the multi-layered reservoir intervals through mode converted shear component data. This paper will discuss the rock physics and properties model that has been developed as part of a 3D 4C PP-PS Joint Seismic Inversion project with the primary objective of delineating and characterizing the various reservoir intervals and depositional environments of the oil and gas accumulation, a first in Petronas Carigali experience in reservoir characterization. This paper focuses on synthesizing missing logs, log conditioning, seismic petrophysical evaluation, rock physics modeling, invasion correction and fluid substitution to the fullwaveform (P- and S-wave) and density logs to make ready for seismic inversion. A total of 10 wells with 8 measured P- and S-wave logs are available for this study. The overall qualities of well logs were adequate for the purpose of this inversion project. These data have been used in the generation of rock physics models. The methodology applied was to construct a rock physics model that is consistent with the petrophysical analysis and the elastic properties as given by the conditioned well log data. The model was then applied everywhere to generate synthetic elastic logs and full offset synthetic seismograms that were then compared and matched to the recorded data respectively. Introduction Well log data are used to understand the relationship between the reservoir properties and subsurface seismic data. Since well log data provide constraints and calibration in the inversion workflow, their quality directly impact the confidence and the accuracy of the inversion results for quantitative interpretation and follow-on reservoir modeling. Well log quality and consistency are subjected to various factors like variation in tool measurements, borehole rugosity, borehole fluids, elapse time between drilling and logging, invasion of borehole fluids into the formations, alteration of the formation properties due to the presence of the borehole and/or borehole fluids, casing points, and missing data. Therefore, the primary goal in processing well log data is to minimize measurement related errors, generate and fill in the missing data, and to obtain consistent and accurate logs between all the wells.

1) Abstract Accurate PVT information contribute significantly to improve metering uncertainty for either topside or subsea business and for multiphase and/or wet gas meters. This is because flow rates need to be provided at standard conditions. Usually, the subsea meters have been set-up using PVT information collected from samples taken during drilling. Rarely this data have been updated after meter installation due to lack of access to quality representative samples. The same issue is raised from a flow assurance point of view by numerous tiebacks to a main subsea production line and with little challenge on the compatibility and effects due to poor access to representative samples. This paper will address the issues regarding access to well stream fluids, ability to capture representative samples, sample handling and storage, and the data needed to recombine the samples and possibilities to implement solutions to these challenges. If subsea multiphase meters serve as the operator' eyes and provide volumetric flow rates of oil, water and gas phases. The data provided by the meters is used also for flow assurance, allocation, and production management and to gain understanding of the reservoir structure, hence the importance of maintaining the measurement over time. As any meters, the measurements are reported at line conditions, where the measurements are taken, usually near the subsea tree, but the operator usually requires the meter to provide flow rates in standard conditions as well. These line conditions measurements are then converted to standard conditions using a dedicated or not PVT model. Depending on the fluids, the method used can have an impact of up to +/-30% uncertainty at standard conditions (Joshua Oldham, Exxon Mobil, at Subsea Tieback 2008). In order to reduce this source of uncertainty, the EOS must be updated as needed. If wells are commingled subsea the only way to gather, the information needed is to sample the fluids at meter conditions in a representative state and recombine them in the lab. The remainder of the paper will describe the innovative tools and methods needed to achieve this. 2) Introduction Oil and gas field operators are increasingly moving into deep and ultra-deep waters to develop new fields. This has encountered considerable success in Brazil, West Africa, and Gulf of Mexico despite the increasing need for more reliant subsea production infrastructures. This trend is also very strong in Asia Pacific with Australia and Indonesia, and lately Malaysia. The vast area full of water in Asia Pacific is only at the beginning of this new endeavor. Increased water depths, longer tiebacks, complex reservoirs and the continuous effort to reduce the cost of the subsea infrastructure, while still ensuring the highest possible recovery rates, raise new challenges in terms of reservoir and production management, flow assurance, and enhanced oil recovery. This is becoming very important with the development cost of such field going way above estimation and in the way slowing down the expansion or the growth of this subsea business for the good of everybody. Pressure and temperature met in these reservoirs are also higher and higher versus time and the fact that production needs to be reported in standard conditions (usually around 14.7 psia and 60 DegF) create anadditional challenge. In this scenario, subsea sampling is rapidly becoming a simple and effective way to gather samples of the produced fluids through the field life, enabling accurate measurements of their properties and the changes that occur through the years.

Abstract With an increasing number of wells drilled deeper and into more severely overpressured formations, we realize that traditional pore pressure prediction concepts cannot always provide the required prediction accuracy. This paper presents a compilation of pore pressure prediction case studies from various areas operated by PETRONAS and is intended to share and discuss lessons learnt from case studies. Comparisons of pressure predictions with real-time or post-drill formation pressure demonstrate which methods and input data resulted in accurate pressure predictions and where and why other predictions fell short. Conventional pressure predictions are often based on velocities derived from seismic data. Post-drill, these velocities may turn out to be far from accurate but even high quality velocity profiles do not necessarily result in accurate pressure predictions. It is necessary to have a thorough understanding of the various pore pressure generating mechanisms that are active in an area of interest. In many basins, the formations that generate high overpressures have never been drilled but pressure is transmitted upwards or laterally to formations penetrated by wells. Basin modelling plays a role in such cases and it becomes important to assess the quality of regional seals, which can trap high overpressure in some structures but may not in others. It is also important to have an accurate geological prediction of formations to be penetrated by a planned well, as regional seals can sometimes be correlated over larger areas. Often, there is insufficient offset well data, or a well may drill formations not previously penetrated, resulting in significant uncertainty in even the best possible pressure prediction. Pore pressure monitoring while drilling can significantly reduce the uncertainty and updating geological correlations and facies interpretations while drilling can be just as important. Introduction East Malaysian basins are considered mature in terms of hydrocarbon exploration. Many fields were discovered in the 1980s and 90s and are still producing today. All producing reservoirs are of tertiary age and reservoir sands are often of deltaic origin. As an example, a conceptual regional cross section for the SW Sabah continental margin is presented in figure 1. Tertiary deltaic sequences are found in a variety of tectonic settings, which can be compressional in Lower to Mid Miocene deposits. Sometimes, this is associated with tectonic uplift, especially in near-coastal ranges. Late Miocene to Pliocene deposits are more likely to be found in extensional tectonic settings, dominated by sometimes very large normal faults. Lower Micoene or older sediments are rarely drilled but are thought to consist predominantly of shale-prone deep-water sediments and are assumed to be the source rocks for the shallower reservoirs. These shales are considered to be relatively poor source rocks but make up for a lack of quality with very large thicknesses. Much of the lower Miocene is presently within the gas generation window. Apart from clastics, carbonate deposits are also important for the Malaysian oil and gas industry, but since carbonate pressure issues are of a very different nature and in the interest of brevity, we only discuss clastics pore pressures in this paper.

Abstract Starting in the early 2000's, we began to see increasing use of Hydrajetting for perforating as a companion to multi-stage fracturing operations. Bundling it within this larger service operation provides for an opportunity to overcome the added costs of using coiled tubing (CT) by developing methods that would allow the CT to stay in the wellbore while performing perforating only minutes prior to fracturing through the new perfs. This can be accomplished by using several different methods for isolating the zone just stimulated without tripping the CT string. This is most cost-effective where the well does not still have a rig, and even more beneficial if the other competitive options for stimulation would also require a stand-by CT string (for screenout, or in case of premature plug setting). More recently, the development of newer types of jetting tools has proven to bean effective method to revive higher perm zones that have recovered very little of the Oil in Place (OIP), especially where well architecture such as slotted liners and bare open hole completions have few or no competitive stimulation options. Several interactions of improving tool life have been accomplished during the past decade, and the need for less horsepower for effective multi-stage fracturing operations allows much smaller footprints than for the commonly applied North American style multi-stage fracturing operations. Also, in countries where any type of explosive charge is very highly guarded and regulated, CT Hydrajet perforating has seen significant application as a stand-alone well completion component. This paper will briefly review the tool advancements and highlight the various applications where Hydrajetted perforations empower various initial completion stimulation methods/techniques as well as several different re-frac recompletion successes from moderate permeability formations to nanodarcy sands and resource reservoirs. Also, some general comparisons of costs vs. the more commonly used perforating/stimulation/completion approaches will be provided, as well as discussion of well production comparisons where available. Introduction This paper will first provide a historical background for perspective on conventional shape charge perforating, then review/compare the benefits and limitations of CT deployed application for abrasive jet perforating. Next, the discussion will center on the revolutionary process introduced in the late 1990's (Surjaatmadja 1998; Eberhard et al. 2000) which began the modern expansion of Hydrajet perforating technology and application. This process started experiencing increased applications into the early 2000's and can be classified as Hydrajet-Assisted Fracturing (HJAF), where all the proppant slurry is pumped through jet nozzles immediately following the Hydrajet perforating stage with no interruption to pumping and repeated multiple times to provide multi-stage fracturing as it is pulled step-wise through a horizontal well. It was introduced before horizontal wells were common, and is still in use today. The third section will cover the process of multistage continuous applications of Hydrajet perforating through CT and then pumping the fracturing slurry down the annulus of the CT and the casing with an immediate isolation of the fractured interval and thereafter repeating this process many times as the CT moves up the hole. This achieves significant time savings as only one CT deployment will perf/stimulate/isolate multiple intervals in either vertical or horizontal completions. Several variations of this process are discussed that, in general, perforate using CT, then fracturing operations are pumped down the annulus, then the process is repeated up hole several times. Various methods to isolate the current fracturing zone from those downhole are employed without removing the CT from the wellbore. In the final section, the application as a CT deployed stand-alone perforating service process, including case histories in conventional completions and unconventional formation well completions, is presented.

Introduction In Malaysia, three known classic deepwater sediments have been identified. The sediments are located on Peninsular Malaysia and Sabah respectively. There are (a) Triassic Semantan and Semanggol Formation in central and western part of Peninsular Malaysia, (b) Oligocene West Crocker Formation outcropping in the onshore NW Sabah and, (c) Miocene to Pliocene Fan System in offshore NW Borneo. These deepwater sediments have been studied in detail by oil and gas industry. The stratigraphic chart for these deepwater sediments are summarized in Figure 1. This paper discusses the recent observations from offshore exploration in Sabah and the insights gained from utilizing the outcrops as analogues to the NW Borneo Fan System especially Mass Transport Deposits (MTD). This paper focuses on integrating the outcrop studies, seismic interpretation with calibration of well logs and image data for deliberating the deepwater systems in offshore Sabah. Discussion on the High Density Turbidite System (HDTS) and Low Density Turbidite System (LDTS) also captured to understand the controlling factor of deepwater sediment distribution. The location of the key outcrops as reported by various authors and the offshore study area for this paper is shown in Figure 2.

Abstract The term "competence" is generally understood to mean, "the combination of awareness, knowledge, skills and attitude that an individual must demonstrate in order to meet the performance standards required of his or her job." Although the primary use of competence in the international oil and gas industry has been and continues to be the identification and closure of skill and knowledge gaps, new and varied uses are being introduced and refined. Some of these new applications include recruiting (especially in cases where large numbers of nationals are needed for new projects), streaming trainees in entry-level training programs, proving employee competence to government regulators before being allowed to work in environmentally sensitive areas and planning and implementing nationalization of key managerial, administrative and technical positions. The expanded use of competence in various human resources activities comes after a steady refinement of the competency concept over the past three decades, from paper-based applications to sophisticated, multi-module computer software programs. Even the notion of "competencies" has evolved during that period, from a beginning as generic, broadly applicable characteristics, to "topics" and finally to the task-based models commonly used in the international petroleum industry today. This paper will begin by briefly tracing this evolution, highlighting examples in exploration and production organizations from the early 1980s to the present. It will then look at specific real-world examples of the "new" uses that have been introduced in recent years. Finally, it will try to gaze into the future to predict further evolution and future uses of competence in the learning and development of oil and gas industry personnel. Introduction The challenge faced by oil and gas companies around the globe is to achieve strong returns on their assets while maintaining the highest standards of operational safety and efficiency. This requires competent and skilled personnel, a task made all the more difficult because on an ageing workforce, a shortfall in the qualified labor pool and increasing government oversight (Donohue, 2013). Regulators are putting increased pressure on companies in the oil and gas sector to prove that their people are competent. Here competency management is about much more than an individual's personal development; it is one of the principal means to ensuring reduced environmental risks and for assuring the safety of others. In today's world, the imperative is not only to assure the competence of employees but also to prove it (Andrews, 2014). The term "competence" is generally understood to mean, "the combination of awareness, knowledge, skills and attitude that an individual must demonstrate in order to meet the performance standards required of his or her job." Since there are no universally accepted definitions related to competency management, for clarity of understanding we offer this brief glossary of terms used in this paper. Competence: The combination of awareness, knowledge, skills and attitude that an individual must demonstrate in order to meet the performance standards required of his or her job.

Abstract Oil and gas well completion approaches vary across different types of practices. The configuration of a well completion depends on the nature of the reservoir and the complexity of its properties. Nowadays, with the availability of advanced strategies and tools, well modeling is getting more sophisticated with the targeting of very challenging reservoir pay zones. Advancements in well completion technology are way ahead of what current reservoir simulators can handle. The details of both old and new well completion technology must be used in simulation calculations to have accurate reservoir simulation results. Moreover, massive amounts of well completion data is available in the corporate database in addition to several simulation applications having different capabilities. This makes it challenging to represent valid well models correctly in reservoir simulation processing applications. Furthermore, well data transmission from the database to reservoir simulation applications undergoes many stages including data fetching, quality checking, formatting, exporting, modeling, testing compliance and adjusting data. In this paper, it is assumed that stages up to data exporting are already implemented since an efficient simulation well information environment is available in place. On the other hand, other stages of well completion modeling are discussed in this paper with focus on having valid completion data for reservoir simulation. Data sources and simulation applications have different data formats and standards. Therefore, there must be an accurate translator that adjusts well completion data and adapts it for the reservoir simulation processing applications. This paper presents a well completion data adjustment workflow that empowers reservoir simulators with significant utilization of well completion data resulting in accurate reservoir simulation results. In addition, examples of a case study are presented in this paper as an application of this workflow. Introduction Wells in reservoir models are the main asset which control accuracy of predicting and matching field production/injection. Therefore, modeling the wells is essential for accurate reservoir simulation. Various well information is captured in a simulation model (e.g., well location, production and injection; and well completion events including perforation, plugging, squeeze and well tests). The well information varies for each well and changes with time. For example, a well could be producing during a certain period of time and then gets shut-in in a later stage. Each well goes over different stages of completion or workovers throughout the reservoir life-time. For example, a well might have a simple initial completion and then a more complex completion later in its life-time because of the need for reconfiguration due to oil depletion or water cut increase. Therefore, well completion data has a major influence on reservoir forecasts, which the reservoir simulators are meant for. This means that the accuracy of well completions affects the precision of any reservoir simulation case significantly. Background The reservoir simulation model is constructed using simulation pre-processing tools and applications. All required information is loaded into these applications to construct the reservoir model for a simulation run. This information covers various types of data, which is retrieved from different data sources.

Abstract Prediction of remaining oil saturation distribution is vital for any mature field re-development project. Identifying correct areas of bypassed oil pockets and remaining oil saturation is the most essential requirement for planning different activities such as production enhancement, infill, EOR etc. History matched simulation models are often used to predict remaining oil saturation at end of history and forms basis for recognizing sweet spots and production forecasting. However, transition from history to forecast, if done on unconditioned reservoir simulation model, often creates large amount of fluid rate fluctuations. This primarily results due to change in control mode from well rate in history to pressure or target rate during prediction often showing either a jump in oil rate or unrealistic oil rate plateau in forecasting. Modifying well productivity index during prediction in typically done to get forecasted oil rate consistent with historical rate. But this corresponds to some unphysical change in model at transition and could significantly change drawdown on which well operates during forecast. As forecast period drawdown becomes unrealistically very different from history match, it downgrades the confidence in quality of history match and also the predictive capability of such models. Although there are several options available in simulators to ensure smooth oil rate transition to forecast but each have their own limittaions and issues. Each of these methods has been evaluated and seen to result in different individual well forecast, leaving different areas of bypassed oil. In mature fields, modeling with an objective of infill candidate identification, production enhancement activities or EOR selection, the presented work explores options to ensure smooth transition from history to prediction without introducing any unphysical modeling artifact in the model. Discussed in the paper are the reasons for erratic transition, available options to correct it, potential impact of using these options and method used to ensure smooth transition from history to reliable forecast. In this paper guideline, workflow and results is presented and discussed supported by actual field examples. In studied fields, applying various options, significant changes in individual well recovery and remaining oil saturation pattern and therby areas of un-drained oil pockets have been observed, which can potentially mis-lead further development scenarios. Background Many oil fields around the world are getting mature and their production rates are on decline. These fields are off their plateaueither because of increasing watercut, GOR or decreasing reservoir pressures, etc. To sustain the production level and enhancerecovery from these mature fields various brownfield redevelopment activities like production enhancement, infill drilling, pressure maintenace and EOR implementation are carried out. Estimating the remaining mobile oil and locating the bypassedoil pockets in mature reservoirs is key to any successful brownfield redevelopment activities. Computer aided reservoir simulation is the most reliable tool to predict the areas of bypassed oil and help in production forecasting for any redevelopment activity. These forecasts are used to determine the economic feasibility of project and aid in investment decisions.

Abstract The transport of solids is often encountered in well drilling, completion, well intervention and production processes. The process is affected by many variables and the complexity of the phenomena presents challenges to the field engineer who is trying to determine how these parameters affect solids-transport even if only one of these variables is changed during an operation. In the early stage, solids-transport studies mainly focused on finding the minimum critical velocity to prevent the formation of a stationary debris bed in the wellbore annulus for conventional rotary drilling with mud fluids. Over the past 10 years, the research and development focus has been on obtaining information related to the prediction of the equilibrium solids concentration profile along the whole well path during tripping in, on the wiper trip speed during tripping out, and on the prediction of the hole-cleaning time. Various correlations and models have been developed that would guide the field engineer to design and optimize the hole cleaning process. However, due to the complexity of the process, a comprehensive and proven model still does not exist at present. In this paper, based on 20 years of research experience, the authors present a critical review of the state of the art of previous approaches to studying the solids transport during both drilling and well interventions. It mainly focuses on theoretical studies. An overview of the experimental study of solids transport is given in a companion paper (Li et al. 2014). The methodology used to develop a model to simulate the hole cleaning process is also discussed. To date, completely satisfactory solids transport software, is still not available for the oil industry. Hopefully, this paper will provide a useful and helpful general guide for future research related to this subject and will aid in a better understanding of the lack of previous studies and what issues should be focused on in future research. Introduction The transport of solids is encountered in various industries which include the mining (Wilson et al. 2006), sedimentation (García, 2008), oil transport, well drilling, well cementing, well completion, and well intervention and production applications. Coal water slurry, iron ore, mineral concentrate, sand removal, limestone or cement kiln feeding in the cement industry, dredging and tailings disposal and heavy bitumen transport are examples of typical slurry hydraulic transport in a pipeline. Figure 1 shows the proppant image which was taken from a downhole camera after a fracturing job in a horizontal wellbore. The sand bed is in the form of dunes that has to be cleaned out the wellbore before the well can start to produce. Otherwise the sands could block the perforations and reduce the production rate. In some cases if the sands are not cleaned out before the production, a high production rate could clean the well. However, once the sand enters the surface lines, it could cause erosion problems for the surface pipeline and other equipment. The cuttings transport in a conventional drilling application involves a drilling period and a hole-cleaning period. In the drilling period, the bit cuts the rock formation and generates the cuttings. As the drilling progresses, the cuttings are transported toward to the surface. Depending on the flow rate and the well deviation angle, cuttings usually form a cuttings bed in the highly deviated section of a wellbore (between 60o and 90o) and form sand dunes between 40o and 60o of the build section. In the vertical wellbore (between 0o and 40o), the particles are usually fully fluidized. Once the drilling is completed, all cuttings should be cleaned out of the hole. The cuttings could be removed out of the hole when the bit remains at the last position (called the stationary circulation hole cleaning mode) or pull the drilling string out of the hole, at the same time the fluid continues to be circulated (called the wiper trip hole cleaning mode). For conventional drilling, the stationary circulation mode is usually applied during the hole-cleaning period since the pump rate is relatively high (annular fluid velocity >1 m/s) and the drill pipe can also be rotated to aid the solids transport.

Abstract The oil and gas industry is constantly evolving. As technological innovations allow companies to explore and produce from energy reserves previously considered uneconomic, companies must grow in ways to deliver against their latest thinking forecast. This dynamic growth means that companies should also have an innovative methodology to build and sustain technical talent that aligns with the business needs, both presently and in the future. Sustainable growth of workforce capability in a changing business landscape is challenging. It is like assembling the pieces of a complex puzzle without knowing how the final product should appear. This paper provides insight into the elements (pieces of the puzzle) that a global oil and gas service company has incorporated into their business-driven competency and employee development program, designed and implemented around a simple, but robust, framework used to support development. This framework has proven to remain aligned with evolving business needs, enabling its thirteen product service lines (PSLs) and ten support functions, in nine regions, to achieve record levels of adoption by its 65,000 employees with competencies defined. This paper also highlights how clear objectives supported by a corporate strategy helps enable individuals to exercise accountability for their own development and the development of others; how a strong, but flexible, program that satisfies the organization, customer, industry, and government requirements can systematically sustain the development of a growing organization; how the elements can be put together to help ensure necessary adoption of the program by responsible parties; and how proactive demonstration of the competence of the workforce can build confidence in the workforce capability. The purpose of this information is to share lessons learned and help other organizations develop competent employees to deliver quality products and services in a safe and environmentally acceptable manner. Introduction This paper discusses the link between business and workforce growth and how effectively building technical talent is instrumental in ensuring that workforce growth does not hamper the business by lagging behind. Building technical talent using a flexible, yet robust, competency program, based on simple and basic employee development principles, is essential in systematically sustaining growth expectations. This relies on a successfully implemented program as well as engaged and competent employees who are willing to contribute to the development of the workforce. Workforce growth occurs in a variety of ways. The preferred methods are organic growth and global mobility. This is where organizations develop employees from within. Employees develop the required technical capability needed for their job titles, promoted based on their demonstrated competence, and/or transferred to other locations based on their demonstrated competence and potential. The organization relies on the existing competency program to be flexible enough to support both of these methods, as well as the assurance that if there is a shortage of internal technical talent, that an external mid-career hire will be introduced in a timely fashion.

Abstract Reservoir compartments are segments that are effectively isolated by structural, sedimentologic or diagenetic barriers that hinder fluid flow laterally between compartments. However, in cases of sandstone reservoirs incising each other, the boundaries of the compartments are poorly defined and huge uncertainties are imposed on the connectivity and fluid flow behavior between them. Various geological and engineering approaches are used to work out the sand-to-sand juxtaposed reservoir compartments in Angsi Field offshore Peninsular Malaysia. In Angsi Field, located in the Oligo-Miocene Malay basin, the I35U and I35M sandstone reservoirs from Group-I stratigraphic unit (coastal-fluvial/deltaic lobes) provide a complicated case of areal and vertical reservoir compartments. The I35U channelized blocky sand incised into I35M mouth bar sand in some parts of the field. Mapping of the interlaced reservoir compartments of both reservoirs is based on conceptual geology, log patterns and seismic data. Although the vertical spacing of the two reservoirs is below seismic resolution, the difference in quality, thickness and fluid type have allowed seismic involvement in delineating compartments. To verify the geological findings, multidisciplinary team seeks out various methods to resolve connectivity uncertainty between the two reservoirs. Fluid gradients supported the idea; however reservoirs fluid contacts are sometimes leveled. Existing oil producers from both reservoirs provides reliable pressure-production data for classical reservoir engineering analysis. Production Decline Curves of both reservoirs vary significantly; seemingly controlled by internal depositional architecture of each reservoir. Depletion Plots further verify no lateral communication between the two reservoirs. Finally, Material Balance proves the understanding of communication between reservoirs; oil-in-place and reserves are aligned with geological studies. Two successful wells drilled lately based on findings from the above approach. A representative simulation model is being built for both reservoirs, incorporating the findings, to plan for further reservoir development and management strategies. This paper shares the geological and reservoir engineering integrated approaches to resolve the reservoir connectivity uncertainties between I35M and I35U, which could be applied in similar coastal fluvial/deltaic settings. The paper also highlights the importance of multidiscipline integration in resolving reservoirs uncertainties.

ABSTRACT One of the major challenges when drilling gas wells in offshore fields is to drill under high pressure and in a loss circulation zone in intermediate hole sections. Heavy mud is used to control the pore pressure in a narrow operational window that create losses and as a consequence, well control issues. Several solutions/ideas have been implemented while drilling this intermediate section, including a thermal-activated resin, rigid rapid fluid treatment, used to regain full circulation and successfully increase the window gradient. The solution to these challenges was developed by designing a fast setting, thermal-activated resin LCM liquid plug with a density equal to 152 pcf. This new treatment slurry was able to be bullheaded and displaced with a polymer mud 152 pcf. The slurry was easily pumped through drill pipe, MWD and drill bits. This paper presents case histories and field applications of this novel polymer-based lost circulation material, for successful treatment of heavy mud losses to formation in wells in offshore gas fields in the Middle East. The paper also includes a discussion of the methodology, material properties and applications. INTRODUCTION There have been many papers over the years referring to why loss of circulation occurs, the different materials available and how to solve it during drilling and while cementing. Basically, loss of circulation treatments can be divided into two categories:1) those where the loss circulation is solved by the addition of solid materials to the drilling mud; and2) those where the problem can only be solved by the use of a non-mud system. Normally when loss of circulation occurs, the first attempt to cure the problem is always by a reduction in mud weight and/or the addition of granular, fibrous, or lamellated material to the mud, but in many cases without success. If no success is obtained by using the solids-laden mud, then it becomes necessary to use the most efficient non-mud system available. Loss of circulation is one of the most time-consuming and costly problem faced by oil and gas well drilling industry. The loss of drilling mud results in increased drilling time, loss of expensive mud, plugging of productive formations, and / or loss of well control. This paper presents a non-mud system solution prepared for challenging field cases in the Middle East where severe drilling fluid loss were encountered. In the cases, thermal activated resin was used to cure drilling fluid loss. LOSS OF CIRCULATION Loss of circulation is the partial or complete loss of drilling fluid or cement during drilling, circulation, running casing, or cementing operations. After the loss of circulation occurs, the level of the drilling fluid in the annulus may drop and then stabilizes at a particular level depending upon the formation pressure. Loss of circulation problems may be encountered at any depth when the total pressure used against the formation exceeds the formation pressure. Commonly, four types of formation are responsible for loss of circulation (Figure 1):a-) natural or induced fractured formations;b-) vugular or cavernous formations;c-) highly permeable formations, andd-) unconsolidated formations. Loss of drilling fluid can result in increased cost, loss of time, plugging of potentially productive zones, blowouts, excessive inflow of water, and excessive caving of the formation. Therefore, application of an immediate solution to loss of circulation is an essential part of drilling engineering. LOST CIRCULATION MATERIAL Fluid loss is encountered in almost all drilling operations. Depending on the severity of lost circulation and the size and type of the thief zone, different lost circulation materials (LCM) are used for curing. LCM is an additive to drilling fluids, cement slurry or frac fluid penetrating a formation. LCM are either insoluble or water soluble and are typically granular (most common), flaky or fibrous. LCM pills are pumped down a well and spotted to build up an impermeable layer on the formation face causing the loss of circulation problem. Sometimes two or three pills are used to stop losses. In most cases, viscous mud pills with loss circulation material allow to temporarily reducing the losses but do not guarantee a durable plugging of the formation. Also, cement plugs can be used but their placement and the time necessary to drill through them make their use relatively costly.

Abstract Nowadays, modeling and simulation software enhancing design and development of hydraulic-mechanical drilling machinery becomes increasingly popular in the offshore industry. The current work presents an efficient way to optimize large, high fidelity models of such equipment. First, a complex virtual model of the selected hoisting system is created and compared with the reference data logs recorded on a full-scale rig. Second, rules and guidelines for conversion of a complex model to a low fidelity model which could be simulated in a real-time (RT) environment are formulated. Typically, a complex model of offshore machinery is suitable only for offline tests. Therefore, to perform RT simulations it is necessary to optimize it. The methodology presented in the current paper provides for interaction with a virtual model in real-time via a full-scale control hardware and software. This in turn allows to perform a hardware-in-the-loop (HIL) test and evaluate developed control systems as well as to verify if chosen control equipment meets the desired performance. Simulation results prove that both high and low fidelity models yield comparable outcomes which correspond well to the reference real world rig measurements. It is concluded that to simplify a model it is important to determine how its particular components affect computational efficiency of the simulation hardware and to clearly understand functions of the considered machine. The paper contributes in two areas. Primary - a high fidelity virtual model of an existing hoisting system is established. The simulated model is benchmarked against real measurements from the offshore drilling rig. Secondary - such a complex model is reduced and confirmed to be applicable for real-time HIL simulations. RT performance can be difficult to achieve even on modern computers due to the stiff nature of hydraulic-mechanical models and high demands on computational power. Introduction High level of technological sophistication, high price and small production numbers are the features that characterize the offshore equipment produced nowadays. According to Bak et al. (2011), manufacturers of offshore machinery are required to have a high level of experience and skills to design and develop their products due to the fact that normally it is not possible to construct prototypes to evaluate if a new design will work. Consequently, design engineers are constantly challenged to find the best possible trade-off between reliability, capacity, and cost of the produced equipment. Therefore, an increasing attention of the offshore industry is directed towards tools and methods that allow virtual prototyping and simulation of new designs which in turn makes it possible for engineers to test, redesign, adjust, and optimize a solution before it is manufactured.

Abstract It shall never be over-emphasized that the balance of cost and value is very crucial in determining the commercial feasibility of a field development or redevelopment project. The values are generated by wells that could fetch higher productivity and could effectively drain out larger reservoir hydrocarbon fluid volume. Well drilling and completion costs and their surface production supporting facilities costs have been steadily increasing in recent years. Subsurface engineering studies shall therefore also focus on optimizing the well placement and orientation, the well type and completion selection, the life-cycle control of well inflow and outflow, with the minimum well count to yield higher values. This paper entails various methodologies of selecting drainage and injection points by combining the remaining mobile oil, current productivity, and current pressure depletion maps constructed from history matched reservoir simulation models. Base on predominant drive mechanisms in the reservoirs studied, governing parameters were coupled in 3 property groups and normalized individually. A known heuristic approach was also adapted to construct a Simulated Opportunity Index (SOI) map. A correlation between the SOI and recoverable reserve (EUR) was established by simulation prediction runs for each drainage or injection point selected, sand by sand in the studied reservoirs. The studied reservoir cases including a vast thin oil-rim reservoir, a huge multiple stacked reservoir, a complex compartmentalized reservoir, and a prolific deep-water reservoir. Clustering the selected drainage and injection points in several sands to further maximize the well productivity, optimization of the inflow control for the selected commingled sands, and the design of cost effective completions, shall be addressed later sequentially in separate papers. Introduction The technical challenge is getting difficult as fields are reaching maturity. The complexity and uncertainty of the field require a detail understanding of both reservoir characteristics and facilities performance in order to identify and optimally exploit the field potential. In multi layered reservoirs, substantial reserves is located in minor reservoirs that demand innovative solution for cost effective redevelopment. The wells drilled in later part of the brown field especially require maximizing reservoir contact, higher well productivity for higher recovery to justify the well cost. Various well architecture options with elaborated smart bottom-hole devices is being deployed to control drawdown and sand production. To achieve maximum recovery with suitable well architecture, meticulous selection of optimum drainage and injection point is critical to boosting recovery from a brown field. Drainage point can be selected once confidence over complex remaining oil evaluation is established. Qualitative and quantitative methodologies ranging from surveillance and performance evaluation to 3D models are used to establish drainage and injection points in matured or brown reservoirs.

Abstract Scale precipitation is a common phenomenon that is a result of chemical reactions that usually occur during hydrocarbon production. It is one of the most common challenges in the oil and gas industry, especially for remote offshore fields. Scale crystals usually cause production losses due to the deposition of scale on the subsurface and surface of equipment and will damage instruments, reduce functionality and increase measurement uncertainties. Deposition of scale influences the performance of multiphase flow meters (MPFM) based on electrical impedance and gamma ray density measurements. Several oil wells of an offshore field located in Arabian Gulf, which commenced its production in 2013 from a heavy oil column lying above a large water aquifer, faced scale build up. The field has encountered a period of water injection prior to its production startup to ensure that reservoir pressure is maintained. The fluid flow rate tests of these wells are conducted through MPFMs. This paper presents the work performed, remedial actions and procedures implemented to maintain MPFM's measurement accuracy in a precipitation environment. This paper will also address the methodology for detecting scale deposition using MPFM measurements compared to scale laboratory detection experiments and water geochemical analysis. The paper will recommend the lessons learned of cleanup operations guidelines for affected MPFMs for calibration purposes.

Abstract This paper describes a Fracture Closure Stress (FCS) treatment to increase the fracture pressure of a significantly depleted sandstone reservoir from 7.3 ppg to 10.5 ppg in a cased-hole application. This treatment was executed on a gas well open to a highly depleted zone of 2.1 ppg and a higher pressured zone of 7 ppg. Previous attempts to fill the well with kill fluid had been unsuccessful due to high seawater loss rates. Efforts to reduce losses by pumping lost circulation material had also been unsuccessful. A FCS treatment was designed to initiate a fracture in the low pressure interval and isolate the tip of the fracture with pill material while allowing the fracture width to grow to increase FCS as needed to control the well. A high-solids content, high-fluid loss pill was displaced with seawater to replicate a hesitation squeeze until the well was able to stand full for a conventional hesitation squeeze. The information in this paper may assist in the planning and execution of loss treatments in other workover applications where the fracture pressure is low and multiple reservoirs of differing pressures are open in a single wellbore. FCS was successfully increased to 10.5 ppg. This successful treatment allowed the well to be filled with kill fluid for all zones open in the well with adequate margin to prevent fracturing to allow rig operations. This paper describes the treatment, execution, challenges, and potential applications of this technology. This paper may assist in controlling wells where the fracture pressure in a zone is low, with other intervals of differing pressure open to the well at the same time. This can be used to successfully prepare such wells for rig operations. It validates the application of this open-hole drilling technology in cased-hole applications. Introduction Loss returns in a wellbore can be differentiated between four main mechanisms; matrix losses, fracture propagation losses, conductive fracture losses, and vugular losses. The mechanism of interest for this subject is fracture propagation losses, where losses in a well occur at high rates when pressure in any part of the wellbore exceeds the fracture pressure of the formation. The Fracture Closure Stress (FCS) concept describes the mechanism by which a fracture in a wellbore initiates and propagates. The FCS concept describes that a wellbore has stress holding the wellbore closed. The stress around the wellbore comes mainly from the lateral translation of force from the overburden stress and also from the pore pressure of the formation.1 Whenever the stress holding the wellbore closed is exceeded by the pressure inside the wellbore, fracture initiates and propagates. The effect of rock tensile strength on fracture pressure cannot be accurately depended on, and is likely to have little effect in most cases.1,2,3 With this, the wellbore can be thought of as a reliable pressure relieve valve, which opens up whenever stress (or pressure) inside the wellbore exceeds the stress holding the wellbore closed (the fracture pressure).1 The stress holding a wellbore closed can change over time. At a certain time reference, the overburden at a depth is supported by both the formation and the fluid within the formation (pore pressure). As fluid in the formation is produced and pressure depletes, more of the overburden is supported by the formation versus the fluid in the formation. While fluid translates pressure equally in all direction, solids do not. The amount of stress translated in the perpendicular direction of a solid object depends on the Poisson's ratio of the rock.4 When a reservoir depletes, and more of the overburden is supported by the formation and less is supported by the fluid in the formation, less of the overburden stress is translated to the lateral plane, decreasing the stress holding the rock closed. This describes the reduction of fracture pressure as reservoir pressure depletes.3,4

Abstract Qatargas is working towards improving operational performance and energy efficiency to reduce its Greenhouse Gas (GHG) emissions. Qatargas' verified emissions inventory portfolio is providing data and trends, which are facilitating an understanding of key emission sources and areas of concern. This has provided Qatargas with a platform to progress a Technology Assessment Study with the objective of identifying opportunities to reduce GHG emissions through energy efficiency and operational improvements. The Technology Assessment Study included development of a screening criteria based on multiple factors such as indicative capital cost (uninstalled), annual reduction potential in tonnes CO2-e per year, cost savings and indicative marginal abatement cost, technical complexity, commercial demonstration/viability and organizational capability. Based on the above criteria, various technological options were explored to enhance process optimization and improve energy utilization. Thermodynamic analyses of energy processes across operations, mass and energy balances, and subsequent SANKEY diagrams were designed to analyze energy flows and their sinks. Correlation of energy flows and emissions, and use of marginal abatement cost analysis were some of the approaches taken to develop technically and economically feasible options for potential implementation. This paper presents these options and provides details on specific projects of interest which could potentially be implemented to achieve process optimization, enhanced energy efficiency and reduced GHG emissions. Introduction GHG emissions are becoming more closely linked to climate change in the minds of the public, stakeholders and regulatory agencies thus motivating companies to reassess their operations, become more energy efficient and reduce GHG emissions so as to positively contribute towards mitigating the effects of climate change. Qatargas understands that its operations contribute to the overall GHG emissions of the State of Qatar and that proactive action is required to manage these emissions. In this context, Qatargas has developed a GHG Management Strategy. The details of this strategy have been provided in a previously published paper (1). An overview of Qatargas' facilities and details on the Technology Assessment Study conducted as part of Phase 3 of Qatargas' GHG Management Strategy are provided below. Qatargas Facilities Overview Established in 1984, Qatargas pioneered the Liquefied Natural Gas (LNG) industry in Qatar and is the largest LNG producing company in the world, delivering 42 million tonnes per annum (MTA) of LNG worldwide from its production facilities in Qatar (see Table 1 for a breakdown of Qatargas LNG facilities per operating asset). Qatargas also operates a condensate refinery (Laffan Refinery) with a daily capacity to process ~146,000 barrel streams per day (BSPD) of condensate feed to produce kerojet, naptha, gasoil and Liquefied Petroleum Gas (LPG). Additionally, Qatargas operates common product storage and loading facilities on behalf of other end users within Ras Laffan Industrial City (RLIC) as part of its Ras Laffan Terminal Operations (RLTO).

Abstract The relative permeability concept has been used extensively in reservoir engineering. As numerical reservoir simulation has become more popular as a tool for reservoir development, the role of relative permeability data became even more evident and important. Its key use is to control the advancement and mobility of different fluids simultaneously coexisting in the porous media, and hence controlling the recovery of the fluids. However, deriving a reliable relative permeability data set remained a major challenge. In reservoir engineering, this challenge has been present for many decades and might be so in the foreseeable future. Another challenge is to have a data set which is internally consistent and does not hinder the simulation performance. Optimistically, with the significant literature accumulated over the years in deriving and using relative permeability, some techniques can be extracted for data quality check, control and assurance. This paper covers the limitations of the conventional methods used for calculating relative permeability from displacement experiments. It also compiles all contemporary techniques in a systematic workflow for quality assessment and consistency evaluation. The workflow has been demonstrated with different synthetic and field examples. This paper will provide a reference for reservoir engineers who have an interest in investigating, checking the quality, and preparing relative permeability data set usable for reservoir simulation process. Introduction Special core analysis (SCAL) is the hub of the evaluation and management of hydrocarbon reservoirs. Relative permeability is one the main constituent of the SCAL which importance is widely recognized for the prediction of oil recovery during displacement by water. As any other piece of data, high quality and reliable relative permeability data set can reduce uncertainty in dynamic reservoir modelling and provide a sound foundation for reservoir engineering studies. Conversely, ppoor quality data can result in lost time due to rework and additional studies, inadequate development plans, and inefficient investment. Relative permeability curves can be generated from different sources such as mathematical models and experimental methods. However, experimental methods are more desirable for two reasons. First, they produce specific relative permeability relationships for specific reservoirs. Second, it is best available approach to resemble the flooding process in the field provided that the experiments performed on representative core samples and fluids from the reservoir under study. Therefore, our discussion will be restricted to relative permeability data are derived from laboratory experiments. The main challenge in the derivation process is how to obtain a reliable relative permeability data set. The term reliable will often be used in referring to relative permeability data set with is a good probability that the defined relationships are representative of the reservoir and inherently repeatable. Judgment regarding reliability will be made according to analysis of results that are judged to have been obtained using valid laboratory procedures. When the term valid is used in referring to laboratory measurements it will mean that none of the procedures used during the test are inconsistent with obtaining reliable results for the sample tested. For instance, the use of an extracted core plug with altered wettability other than the reservoir one would generally mean that the results are invalid. The source of unreliability may be attributed to the following reasons:The derived relative permeability data set are usually prone to excremental artefacts.The state of the experiment does not fit the model's assumptions used to derive the relative permeability data sets. In another word, the methods of calculating relative permeabilities from data obtained from displacement experiments don't describe all physical effects encountered in the experiment.

Abstract In order to economically develop the Albian Carbonate Macae formation in the Campos Basin Deepwater Brazil an extended reach horizontal well is required. Due to the tight nature (low permeability) of the rock, stimulation of the reservoir is required. Completion designs and techniques for treating extended reach horizontal wells in deepwater are limited. Most applications for these type wells in Deepwater are ineffective (high skin/low PI) and inefficient (trip/time intensive) affecting project economics. A completion system was developed that allows for safe, effective and efficient stimulation and installation of such an extended reach horizontal well in Deepwater. This paper will describe the design, testing and execution of a unique Deepwater completion system that adapts a known multi-stage ball drop system used in onshore unconventional reservoirs, for example the US and Canada, to a known horizontal open hole sand control system to effectively matrix acidize a 2000 m horizontal open hole thru a Limited Entry Liner with reservoir segmentation. The system uses a Retrievable Ball Drop Diversion System (RBDDS) consisting of multi-stage frac sleeves run on wash pipe. The RBDDS is run inside a limited entry liner that is segmented into stages or intervals by openhole programmable interventionless packers (Mendes et al. 2014) all run in a single trip and with no pipe manipulation required while stimulating. It furthermore leaves behind a robust lower completion system for the life of the field. This 2000 m lower completion system was successfully run in the Albian Carbonate reservoir and all stages treated with 15% HCl with minimal NPT, no harm to people or environment. At the time of completion, this well was the longest horizontal reservoir section and longest step out well drilled and completed in Brazil. This Limited Entry Liner System together with the RBDDS proved to be a very efficient, effective and deepwater friendly system. Introduction Low permeable deepwater carbonate reservoirs have created many challenges to produce economically. The wells typically require extensive reservoir contact that has to be stimulated in order to achieve an acceptable Productivity Index, PI. Field A, Albian Carbonate in the Campos basin offshore Brazil falls into this challenging category. Effectively stimulating long horizontals has long been an industry challenge onshore and even more so in a deepwater environment. With the advent of Unconventionals in the US and Canada the ability to stimulate long horizontals has generated a great deal of focus and effort over the last few years. The high rate and multi-stage fracture stimulations done on these wells has resulted in the development of new industry techniques, notably using frac sleeves operated by dropping balls, and pumping down plugs and perforating guns to isolate and perforate each stage. This paper will review the concept selection process, detailed design work, testing, and implementation results of an extended reach horizontal well that utilizes onshore Unconventional ball drop technology adapted to a Deepwater setting to effectively stimulation a 2000 m long horizontal section. The well and stimulation treatment was considered an apparaisal effort such that if the production from the well is suitable it will open up the full Albian Carbonate for further development.

Abstract Digital Rock Physics (DRP) has significantly evolved in the last few years and added invaluable contributions in improving core characterization and in providing high quality advanced SCAL measurements, emphasized through various studies (Al Mansoori et al., 2014 and Kalam et al., 2011). This paper represents a unique DRP relative permeability SCAL study done on two plug samples from a carbonate reservoir in the Middle East. It outlines the DRP method used to determine the relative permeability curves including sub-sample selection, high resolution CT scanning (down to nano level), generation of the 3D rock models, and simulation of fluid flow displacements. The paper will also discuss the power of pore scale imaging and how it helps in understanding macro property variations. The DRP results are comparable to the SCAL results of same formation of nearby fields and are currently being used for the Full Field simulation. The conclusions will be supported by a comparison with physical lab measurements that were done independently on samples of the same formation from the same well's core. Such comparison will demonstrate the added value in using DRP, and will show the effectiveness of the technology in generating advanced SCAL data in a significantly shorter timeframe compared to conventional laboratory measurements. Introduction Relative permeability (Kr) curves provide macroscopic description of the way in which two (or three) phases flow together locally in a porous medium (Honarpour et al., 1986 and 1995; Heaviside, 1991). Imbibition water-oil Kr data are critical in the evaluation and management of fields having natural water influx or having planned or actual water-flooding. However, high percentage of such laboratory measurements yields unrepresentative data that cannot be used in reservoir simulation models or as input for history matching of production profiles. In addition, the traditional laboratory evaluation methods may not be applicable to every testing condition or every type of reservoir rock and hence the continued development of laboratory methods is required to help characterize and understand challenging reservoir behaviors (Dernaika, 2010 and Serag et al., 2010). Digital imaging technology has been extensively used in the petroleum industry to obtain fast and reliable core data from reservoir rock samples. The technology (Digital Rock Physics) has contributed reliably to reservoir core characterization through the application of Dual Energy X-ray CT Scanning (Walls and Armbruster, 2012 and Al-Owihan et al., 2014) and to the prediction of reservoir engineering quantities like capillary pressure and relative permeability through direct simulation into high resolution 3D images (Amabeoku et al., 2013, De Prisco et al., 2012, Mu et al., 2012 and Grader et al., 2010)

Abstract Conventional calculation method for analyzing riser mechanical behavior is based on the fourth-order differential equation. In this paper, a simple analysis model and calculation method has been provided. The whole riser is modeled as a continuous beam-column with N span under actions of both axial and lateral loads. One span of the beam-column is cut out as an equilibrium unit to establish the equilibrium differential equation which is different from previous governing equation. Results shows that the equilibrium differential equation established can deal with any kind of lateral force of riser. However the difficulty of solving riser behavior governing equation is reduced through transforming the four-order differential equation into a second-order one. The correctness of the analysis model and the calculation method has been verified through case study at last. Introduction Marine riser is the key equipment connecting subsea wellhead and floating drilling platform (ship) in deep-water drilling and exploration. Scholars have done quite a number of researches on riser mechanical behavior. Cliton G. Gosse(Cliton G. Gosse and G. L. Barksdale,1969) developed a mathematical model to analyze the marine riser behavior, and the nonlinear differential equation describing the static mechanics is solved by using the finite-difference approximation. Burke B G (Burke B G, 1973) deduced the riser mechanical deformation control differential equation with elastic mechanics method. Robert M. Sexton et al (Robert M. Sexton and L. K. Agbezuge, 1976; T.N.Gardner and M.A.Kotch,1976) developed a computer model making a dynamic analysis of the riser by calculating the riser stress, deflections and lower ball joint angle. Bruce E. Bennett (Bruce E. Bennett and Michael F. Metcalf, 1977) made some nonlinear dynamic analysis of coupled axial and lateral motions of marine riser, and the analysis method allowed engineers to investigate riser pipe bucking stability. W. R. Azpiazu (W. R.Azpiazu and V.N.Nguyen, 1984) analyzed the vertical dynamics of marine riser to determine the amplitude of dynamic forces and displacement caused by heave action. A. D. Trim (A. D. Trim, 1991) derived an equation of axial motion of a tensioned marine riser and a number of partical problems were considered, including the dynamic response following an emergency disconnection. V. J. Modi et al (V.J Modi et al, 1994) derived an equation of motion for a marine riser undergoing large deflections and rotations. Geir Moe (Geir Moe and Bjern Larsen, 1997) developed a differential equation describing the motions of marine riser with asymptotic solution. Chainarong Athisakul, et al (Chainarong Athisakul, et al, 2002) presented a variational approach to two-dimensional large strain static analysis of marine risers. A. Ertas (A. Ertas, 2006) proposed the riser dynamic differential equation, which is solved by the finite difference method. Khan R. A. (Khan R. A., 2006) made some dynamic analysis of risers subjected to regular or irregular wave with ABAQUS software, and the variation of riser bending stress with low frequency drilling ship movement and wave motion and current velocity were also analyzed. Chang (Chang, et al, 2008; Sun, et al, 2009; Ju, et al, 2011) did some research on riser stochastic nonlinear dynamic response, hanging axial dynamic analysis and wave-induced long-term fatigue analysis with theoretical and numerical simulation method. Zhou (Zhou et al, 2013) studied the mechanical properties of riser subjected to shear flow with experimental method and found the riser "one third effect" which can be explained through an analysis of the mechanical model and material mechanics theory. The purpose of this paper is to analyze the mechanical behavior of riser using Beam-Column Theory.

Abstract Discrete technology solutions, such as real time data acquisition, distributed temperature sensing, etc. applied on selected-well basis seem to serve field development engineers well sometimes. Nevertheless, for engineers continually to improve field-wide operations and attain the cost and production advantages necessary to stay competitive in an industry shifting to cost-effective applications, integrating workflows is a strategic imperative. Engineers will need to concentrate and excel not just on specific technologies but on holistic rigless operations success driven by more attention to integration than individual technology solutions. The challenge facing asset teams remains how to execute comprehensive plans to make significantly higher returns from capital technology spending in the field. The scope of this paper is to present how engineers have adopted technology integration and alignment of numerous technology solutions for the specific situation of successfully developing and managing a giant oil carbonate field in readiness for a major production milestone. The approach presented entails an all-inclusive project-based method that involves performance reviews, elimination or reduction of idle times through close monitoring of incremental project stages, optimizing operational efficiency through increasing the speed of material delivery to the well sites, and improvement of logistics of people and equipment. The approach involves unifying role-based, process-based, and production workflows throughout the operation and building on a learning curve with each successive rigless operation. From the safe job execution of over 100 rigless activities, a model or scorecard is available to control important variables, assess the effectiveness of specific technologies, and provide support for leading or lagging indicators. As a result of seamless and routine inclusion of technology-based exercises at a project level, rigless activities have been completed over 60% faster than when the campaigns started nearly five years ago. Monetizing this value of technology integration in auditable and quantifiable terms translate to significant gains over the course of the rigless campaign. Through integration, engineers can implement effective programs for improvement in service levels and improve operations. Eventually these gains translate to fewer obstacles to project delivery. Introduction Technology is core and central to Manifa field development. Achievements in the Manifa field are testament that the field development team is savvy about applying fit for purpose technological solutions for lasting/sustainable gains. As a result of measurable improvements and integration of workflows between core technology applications, several world firsts have been credited to the Manifa team (Arukhe et al., 2014). Some of these records include the world's largest extended reach project (more than 75% if the field's wells are ERWs) and the use of the world's first tandem 2.125" CT tractor for ESP open hole completions (Arukhe, Duthie, Al-Ghamdi, Hanbzazah, Almarri, Sidle & Al-Khamees (2014). The first oil industry use of a specialized reusable filtration unit system in a long-term injection test, utilizing primary seawater filtration and chemical treatment was conducted in the field. A reflection of the project, upon successful commissioning of the first phase, reveals that the most critical success factor includes the degree of technology integration into the team's basic strategic approach to field development. The amount of solutions for rigless well interventions and well testing have multiplied considerably lately – from optimizing CT reach, well stimulation, multilateral access, and profiling to well testing. At present, these solutions deliver gains with possibility of influencing more efficient field development. As shown in this paper, technology adoption in CT reach and stimulation treatments results in gains from accelerated job execution and client satisfaction becomes evident. Consequently many wells have been successfully stimulated onshore and offshore.

1) Abstract In subsea business, the use of wet gas or multiphase flowmeter is becoming a standard for the deep and ultradeep field development. The business growth has been outstanding over the last few years and will continue. In the meantime, the tieback of these fields to hosting platform or onshore facility has increased drastically, in Australia it is few hundredth kilometres. In such conditions there are more and more satellite fields hooked to the main pipeline subsea. This leads to issues with custody transfer and fiscal allocation. Already production are transferred between countries under this scheme, tax, royalties, regulations need to be fully taken into acocunt and understood wihtout using anymore fiscal metering at surface. Under these schemes of development, the criticality on the measurement is not only high accuracy flow rates with one meter per well but also on how to guarantee the performance over the years knowing that the production of each phase is changing versus the well ageing. Therefore, a versatile solution is compulsory where no physical access can be done easily and where the use of Subsea Sampling is unfortunately limited yet, showing a lack of understanding on the fluid behavior criticality about the flow assurance too. What can be done to ensure and audit the meters? API Chapter 20.3, NPD (Norway), DECC (UK), ISO TC 193 have been already met some recommendation. One meter is complying with this recommendation and then field experience and results versus fiscal metering will be presented. This paper will show the challenges in Brazil, North Sea and Australia. The real economical value of a subsea meter will be briefly highlighted in this paper. How can it impact the production by being the eye of the oil operator during the production phase? Cost of installing meter or replacing meter versus the gain will be shown in few cases. this paper is addressing also the use of multiphase flow meter beyond the classical metering flow rate performance and focus on the benefits of brought for a subsea flow assurance and reservoir management and the cost effectiveness of a subsea deployement versus a surface one. 2) Introduction In the petroleum industry, allocation refers to practices of breaking down measures of quantities of extracted hydrocarbons across various contributing sources. Allocation aids the attribution of ownerships of hydrocarbons as each contributing element to a commingled flow, i.e. where produced fluids from multiple wells and/or producing zones are combined before flowing to a surface facility, which in deep water is typically a floating production, storage and offloading (FPSO) unit. Commingled flow is becoming increasingly common in the growing number of deep-water developments, where subsea production facilities combine flow before joining riser systems that transport hydrocarbons to the surface. Such systems often include tiebacks to other oil or gas fields operated by different company partnerships. Allocation of produced hydrocarbons has major fiscal consequences for a variety of involved parties. It directly affects the revenue and tax liabilities of oil and gas operators and is the subject of increasingly stringent guidelines and regulations from industry bodies and government authorities. Manufacturers of equipment and suppliers of services to the oil and gas industry are challenged to meet the requirements of these guidelines and regulations, and have developed new technologies and processes to enable more accurate measurement of hydrocarbon production on a well-by-well basis.

Abstract Current offshore marginal field development and mature field re-development in Malaysia consistently encountered high development cost and low recovery or incremental recovery. Wells are being drilled and completed at a typical cost of 10 to 35 MM$ per well while the estimated ultimate recovery (EUR) per well is as low as < 0.5 MM Bbl. The corresponding well development cost (WDC) can be higher than 20 to 70 $/Bbl. This high WDC cost, and accordingly high UDC (including surface facilities) and UTC (including operation) cost can significantly deteriorate the commercial development feasibility of our resources. In this paper, correlations between EUR and NPV in several key field development projects were first presented to illustrate the art of balancing cost and value on increasing the EUR per well and reducing well cost in various stages of the IOR and EOR projects. A simple chart of "Cost vs. Value" was used to determine the commercial feasibility of well construction and field development plan. This paper also entails discussions on changing the way we do for well placement and reservoir contact well path design to optimize reservoir drainage and to reduce well counts. Then it proceeds on discussion of changing well architecture and completion design using new and advanced technical approach, methodology, and technology for optimizing down-hole flow control and sand production control, in the quest for increasing well productivity and EUR per well. dditional examples of marginal field development, brown field redevelopment, and EOR project development were further used as exhibits to illustrate the importance of balancing the cost and value in field development planning and implementation. Introduction Development or redevelopment of a field involves the determination of subsurface reservoir drainage potential, the construction of a production system for life-cycle production and operation, and the implementation of a fluid and power processing, transportation and delivery system (cable, pipeline, FPSO and tankers). The value is solely estimated based on subsurface reservoir drainage and sequential reservoir depletion plan either by reservoir model simulations or by analytical methods. The cost is incurred by the construction of wells with optimized completions, capable of handling life-cycle oil, gas, water and sand production, by the construction and continuous modification of the surface support and fluid transportation facilities. Figure 1 illustrated this integration on value and cost. Well construction is the key link bridging the subsurface potential and commercial feasibility of the field development. Well value can certainly be optimized by well design increasing reservoir fluid contact, improving fluid displacement, maintaining or minimizing reservoir pressure decline. This entails the determination of the optimum reservoir drainage and injection points (Ref. 1), selection of the well type (Ref. 2), optimization of well reservoir multiple contact trajectory design (Ref. 3), optimization of smart (Ref. 4), sand control (Ref. 5), and artificial lift completion (Ref. 6). Well cost can also be optimized by first minimizing the well counts (Ref. 7), further simplifying the well completion (Ref. 8), modifying the drilling trajectory (Ref. 9), optimizing drilling schedule and offline operation to minimize the rig days (Ref. 10).

Abstract Hydraulic fracturing is practiced to stimulate unconventional and tight oil and gas reservoirs. This technique increases the deliverability of reservoir by inducing reduction in pressure drawdown and exposing more reservoir contact; hence, improving the well productivity index. Fracturing can also help to break through and pass near well-bore severe formation damage and can make low permeability and tight reservoirs economically viable. Prior to execution of fracturing job, the feasibility of the operation can be accessed through analyzing the effect of skin on overall deliverability of the system. Valuable extent of research has already been done to analytically model or numerical simulate the whole scheme for evaluating this effect. While the orthodox analytical approach to address this problem incorporates simple assumptions, an attempt has been made to build a semi analytical correlation. This paper proposes a mathematical correlation to determine equivalent skin in hydraulic fractured system for pre-analysis of hydraulic fracturing obtained through numerical simulation modeling. The paper describes two 3D simulation models scenarios; Scenario 1 is without hydraulic fracture and Scenario 2 is with hydraulic fractures. Both scenarios consider the anisotropy (different Kx and Kv) in the system. Scenario 1 has been run for the whole range of matrix permeabilitity values from 0.001 to 1 md. Scenario 2 has been run with different sets of varying fracture's lengths, fracture widths and fracture permeability as well as matrix permeabilities. The two scenarios with corresponding matrix permeability are comparatively analyzed and skin has been determined by calculating fold of increase. Total number of 29040 Data points are obtained by the 29040 number of simulation runs by coupling the commercial reservoir simulator with Matlab. Multivariate regression technique is used to obtain generalized correlation for skin as a function of hydraulic fracture and matrix permeabilities properties. 20000 data points are used to develop proposed correlation and remaining 9040 data points are used to validate and test the proposed correlation. The newly derived correlation was compared with prevailing analytical approach for skin estimation. It has been found that the degree of absolute percentage error, average percentage error and standard deviation by using of this new correlation has reduced to 3.21%, 3%, and 6.4 respectively.

Abstract One of the most useful features of decision analysis is its ability to distinguish between constructive and wasteful information gathering. Value-of-Information (VOI) analysis evaluates the benefits of collecting additional information before making a decision. VOI models describe the relationship between the uncertain quantities of interest, the reliability of the information and the decision criteria. Many uncertainty quantities are continuous in nature and the probability distributions that describe their uncertainty are discretized, and presented in decision trees, to simplify analysis. A three-point discretization of a continuous distribution is standard, and often preserves the main characteristics (central tendency, spread) of distributions that are close to symmetric. However, VOI studies rarely, if ever, include an analysis on the sensitivity of the VOI to the quality of the discretization. In this work we investigate a variety of discretization techniques, for a range of typical information gathering situations. The investigation utilizes a robust model that accurately calculates the VOI for any combination of continuous distributions. The key criterion for assessing a discretization techniques is whether or not they it has a significant impact on the decision to collect the information. The goal of the work is to provide practical guidance on the level and technique of discretization required. Introduction. Most of what petroleum engineers or geoscientists do involves "acquiring" information, with the aim of improving decision-making. "Information" is used here in a broad sense to cover such activities as acquiring of data, performing technical studies, hiring consultants, or performing diagnostic tests. In fact, other than to meet applicable regulatory requirements, the main reason for collecting any information, or doing any technical analysis, should be to make better decisions. The fundamental question for any information-gathering process is then whether the likely improvement in decision-making is worth the cost of obtaining the information. This is the question that the VOI technique is designed to answer. The oil and gas literature includes a number of papers (e.g. Begg et al, 2002; Bratvold et al, 2008) and books (e.g. Bratvold and Begg, 2010; Newendorp and Schuyler, 2003) where VOI analysis is introduced and described in detail. It is common to use decision trees to structure and evaluate the VOI decision. If the underlying uncertainty is continuous in nature, one of the common discretization methodologies such as Extended Swanson-Megill, Extended Pearson-Tukey, or the McNamee-Celona is often used to discretize the underlying uncertainty into a few, usually 2 or 3, degrees(Bickel et al. 2011). In general, the discrete probabilities and values are selected with the aim of matching the moments (mainly the mean and variance) of the continuous representation. In this paper we refer to this approach as the Low Resolution Decision Tree (LRDT) approach. A few papers discuss the calculation of VOI when the uncertain event of interest is continuous (Chavez & Henrion, 2004; Arild, Lohne, and Bratvold, 2008; Bickel, 2012). However, the VOI calculation approach in these papers is presented using different terminology than what is used in the LRDT approach. Furthermore, the papers are either limited to relatively simple problems or have very different representations of the reliability or quality of the information gathered. Despite the fact the LRDT approach can have significant errors, VOI calculation are rarely conducted using the full continuous representation of the uncertain event of interest. We suspect that the reason lies in the issue discussed above.

Abstract This paper describes the use of an innovative high-performance water-based drilling fluid system in south Europe. The novel drilling fluid allowed to successfully drill a sidetrack in a deep, high pressure-high temperature (HP-HT) well, in an area where low toxicity oil-based drilling fluids had been used in the past, due to the adverse drilling conditions. Comprehensive laboratory testing carried out to customize the drilling fluid formulation during the well planning phase, was complemented by further testing conducted during drilling operations. An obvious advantage of this system is its simplicity. It is composed mostly of liquid additives that allow a quick and easy preparation at rig site. The system is also compatible with the full range of mud densities, while exhibiting consistently superior lubricity characteristics. A tailored version of the system for this sidetrack well in southern Europe, required a heavy weighted fluid (up to 2.06 SG) to provide sufficient hydrostatic pressure for well control. The formulation included a high temperature rheology modifier that improved fluid stability at temperatures up to 160°C at total depth. A high performance lubricant was added to the system to improve drilling rate, while using an advanced steerable drilling system. Lubricity coefficients were monitored and recorded daily at rig site using a standard industry accepted ring and block type lubricity tester. The lubricity values fell in the range traditionally associated with oil-based mud usage. The successful sidetrack operations were completed with very good performances. Introduction Drilling fluids can influence all processes of well construction and operation, since incompatibility between the selected fluid and geological conditions yields many undesirable consequences in terms of drilling issues, quality of the production zone and economical performances. This is even more "true" when operating in complex drilling conditions, such as those described in this paper. In particular, one of the first applications of an innovative high performance water-based mud (HPWBM) outside the United States - it had been previously used only once in Europe - is reported herein, which made it possible to successfully drill a challenging sidetrack within a deep, high pressure-high temperature (HP-HT) well, in hard and tectonically-stressed formations. The HPWBM, optimized to the specific field conditions, met several standards for effectiveness: high lubricity, stability at high temperatures, little tixotropy, resistance to solids contamination. The fluid represented a big step forward in reducing the environmental impact, while providing performances comparable to those of low-toxicity oil-based muds used in the area for the last 20 years, as the only means to overcome the difficult drilling conditions. The reservoir is characterized by a white light brown dolomite of the Triassic age, and has two main hydrocarbon zones, an upper and a lower one. The sidetrack's target was the upper reservoir, which is an isolated fault block in the west area of the field resulting from a series of tectonic discontinuities, that had remained undrained by the previous operations. The depth of target reservoir was between 5500 and 6000 m, with a temperature of up to 160°C and pressures over 1000 kg/cm2 at total depth. In the offset wells, these demanding conditions, combined with the high formation hardness and the significant tectonic stresses, had leaded to such drilling issues as high torque, low rate of penetration (ROP) and wellbore instability. Instead, in the case described in this paper, the usage of the HPWBM, in combination with an advanced steerable drilling system, enabled the sidetrack to be successfully executed without incidents.

Abstract Low resistivity low contrast (LRLC) pays/intervals mostly are being examined via behind casing analysis and produced thru production enhancement works from idle wells in numerous oil fields in Malaysian Basin. However, with the aim of unlocking hydrocarbon volumetric LRLC potential, it should include seismic data analysis in addition to formation analysis behind casing. In the past, these LRLC intervals were often ignored and considered as water-wet sands due to high water saturation or as tight sands. These intervals, which contain significant reserves, have been recognized and presented in several technical papers explaining its appropriate identification and evaluation techniques using well-data (logs and samples/cores). The economic importance of LRLC pay sands in the Malaysian Basin has just recently been demonstrated. These pays may lead to a large areal extent and may contain ten to hundred millions barrels of hydrocarbons. The integration and proper techniques of petrophysics and geophysics may become a vital approach for understanding the hydrocarbon distribution (volumetric) within a large areal extent. The possible environment of depositional for developing LRLC reservoirs are: 1) deep water fans including MTD (mass transport deposit), 2) turbidites, 3) shoreface (middle to lower part), 4) delta complex (i.e. delta front and toe deposits), and 5) channel fills. The LRLC may not occurred in alluvial fans and aeolian deposits. These 5 environment of depositions may accumulate several types of LRLC sediments such as: laminated intervals; bioturbated intervals (with dispersed and/or structural clays); altered framework grains and/or smaller grain size (i.e. silty sand reservoir). The thinly laminated sand is probably the most significant reservoir in term of producing hydrocarbon comparing to the other LRLC types. The understanding of logging tools (wireline, LWD) and its responses can be used to build petrophysical and rock-physic models that can evaluate these LRLC reservoirs. But having available advanced logs such as NMR, Image, sonic (Vp and Vs) logs, it is a plus for a better analysis. Furthermore, an elastic property (rock physics) from seismic data may establish a clear separation for different lithology and fluid saturation on LRLC sands and may lead to future recommendation work on LRLC reservoir characterization. The objective of this paper is to provide the above understanding with explanation and examples. Introduction In Malaysia basins, the LRLC (Low Resisitivity Low Contrast) sands are being recognized and brought into production recently. Previously, these sands were considered negligible in term of its commercial; but now, it has enough evidence confirming by available well-data that these sands are of economic importance. With occurrences of numerous productive intervals have been indentified, it encourages us on understanding further on its geologic background, depositional scheme, geophysic assessment, and proper formation evaluation from available well-data such as well-logs, cores, and production history.

Abstract Located in the Partitioned Neutral Zone between Kuwait and Saudi Arabia, the South Fawares field has been producing from the Lower Cretaceous Ratawi reservoir since 1956. Several conventional coiled tubing acidizing treatments have been performed to restore productivity from the Ratawi formation. However, due to the formation heterogeneity, limited zonal coverage and inconsistent acid distribution, these treatments resulted in limited improvements to productivity. The objective of this study was to determine the most appropriate re-completion/stimulation technology that could achieve the following: Effectively and evenly stimulate the entire horizontal section,Benefit from the vast network of natural fractures within the formation matrix to further enhance production, andMaintain wellbore integrity. This paper presents a successful pilot project implementing horizontal open hole multistage completion systems for the first time in the South Fawares field. Existing lateral sections drilled across the Ratawi formation in the South Fawares field were segmented into several stages and each stage was fracture acidized separately to achieve optimum acid placement and maximize the net stimulated reservoir volume. The results show that effective wellbore isolation between stages coupled with efficient diversion of the stimulation fluid is key to improved well productivity. This paper highlights the planning, execution and challenges of the installation of these systems with comparisons of pre- and post-stimulation data and offset wells. The success achieved from the first deployment of open hole multistage completion systems in the South Fawares field has opened new opportunities for reviving the productivity of additional depleted wells. Introduction The South Fawares field is situated in the Partitioned Neutral Zone (PNZ) between Kuwait and Saudi Arabia, (Fig. 1), where the natural assets are shared jointly under the Neutral Zone agreement signed in 1922. Since 1949, Saudi Arabian Chevron, a 100% owned subsidiary of Chevron, the Kuwait Gulf Oil Company and their predecessor companies have operated four oil fields in the onshore PNZ. The fields are Humma, South Fawares, South Umm Gudair and Wafra. In 2009, the 60-year agreement between Saudi Arabia and Chevron predecessor, Getty Oil Company was amended and extended for another 30 years. Under this agreement, Chevron operates Saudi Arabia's 50 percent interest and the Kuwait Gulf Oil Company operates Kuwait's 50 percent interest in the PNZ.

Abstract Corrosion is a critical problem during Oil/Gas production, especially in sour field, Hydrogen Sulfide is the biggest contributor in the corrosion of production facilities. During the production period, pipeline will be corroded with reaction between H2S and Fe. This reaction will be occured differently in various temperature which determines the rate of your pipeline becoming thinner and thinner then will be unsafe. This paper presents a study about corrosion phenomena in production pipeline in sour field by analyzing the heat transfer to determine the corrosion rate in every part of the pipeline. An analytical model for heat transfer is coupled with fluid flow model, frictional heat and considering the Joule Thomsoneffect for steady-state condition. Then, from the analysis of the heat transfer, the corrosion rate in every section of the pipeline, 300 ft, will be obtained. This corrosion rate is determined from the analytical model. This model is applicable to be used in onshore and deepwater cases, depending on the surrounding condition. Thus, the position in which corrosion happened worst can be located. Coating or doing material selection for the several part of the pipeline could be a solution to prolong the age of the pipeline. Effectiveness is about how long the coating or the material selecting would be placed. Then, it could finally contribute in economical analysis about how much would be invested to reduce the impact of corrosion to assure the better production. 1. Introduction It is a fact that corrosion is always happened during oil/gas production and there is nothing to do to eliminate it. The only way to do is to make the process occur more slowly. Corrosion will damage production facilities which are exposed by the fluid and surrounding environment containing corroding agents such as H2S, CO2, etc. In this paper, the main concern is H2S as the agent which can trigger the corrosion process happens. The existence of corrosion on the production facilities will disturb the flow assurance and make the production cost increase. Corrosion will make the pipe wall become thinner, then reduce the diameter of the pipe. Corrosion will also change the pipe roughness. Thus, these two occuring phenomena will significantly change the flow characteristic, then damage the flow assurance. In order to ensure the flow assurance, preventive actions such as pipe coating, injecting inhibitor, etc are always done. In the other hand, all of those actions also have to be considered from the economic view. Thus, a right action has to be chosen to ensure the flow assurance and also be economically done. In this paper, authors develop mathematical model to choose and predict the right action to be executed. Authors also suggest pipe coating and material selection as a right solution to answer the flow assurance problems in that condition.

Abstract The drilling induced tensile fractures can be observed from borehole image logs but they must be differentiated from natural fractures. This paper focuses on the understanding of hydraulically or artificially induced tensile fractures while drilling. We present an inversion method using rigorous principles of mechanics, to determine the in-situ formation stress state from observed induced tensile fractures. Contrary to common practices where only vertical or near vertical wells can be analysed, the present method is applicable to wellbores of all orientations. For a geological rock formation and area where the in-situ stress regime can be assumed to be similar, all the relevant borehole image logs can be included to provide information to yield the most probable subsurface in-situ stress state. The proposed inversion method directly solves for the in-situ stress states given any single set of observed tensile fracture location and orientation. It provides not only an estimate for the minimum horizontal stress magnitude and direction, but also the maximum horizontal stress magnitude which is usually very difficult to pin down. The resultant equations are non-linear and a simple numerical scheme is adopted for the solution. Although published data on borehole images of fractures with corresponding in-situ stress information are scarce, two observed field data from published papers are chosen for comparison. Introduction In-situ stresses in deep rock formations reached equilibrium over geologic time; but drilling, production and injection processes cause deformation in the rock mass and change these stresses, and often negatively impact the operator's development plan. If they are not well anticipated, the challenges and costs of managing a prospect can far exceed the initial field development expectation. Therefore, it is vital to characterize the undisturbed in-situ stress and evaluate potential impact of field development induced rock stress changes. Two examples that come to mind are 1) enhanced oil recovery field development where injection scheme takes place under hydraulic fracturing condition and 2), the development of unconventional resources such as shale gas, where the effectiveness of hydraulic fracturing to access hydrocarbon is impacted by the in-situ stress regime. The latter, for instance, is encountered in China's Sichuan basin where operators are striving to determine whether hydraulic fractures in certain areas of the basin are developed under thrust-faulting or reverse-faulting stress regime (Yuan et al, 2013). A reverse-faulting stress regime implies that the hydraulic fractures would grow in a horizontal 'pancake' fashion, diminishing its effectiveness in draining the reservoir.

Abstract This paper has proposed a novel approach for evaluation of polymer flooding potential during oil reservoir development, which has integrated orthogonal design and BP artificial network. This paper firstly divides the evaluated polymer flooding reservoir units into four styles using Weighted Euclidean Distance method. On the basic of unit sorting, we have generated predictive samples sets for polymer flooding potential with orthogonal design and reservoir simulation. In order to enhance the reliability and prediction ability of the polymer flooding network models, this paper has created a new orthogonal experiment design table to meet this study. It can cover the evaluated reservoir blocks but improve the extendibility of the network by enhancing training sample numbers. After that, Enhanced Oil Recovery(EOR) and Internal Rate of Return(IRR) predictive models of polymer flooding are constructed using BP artificial neural network method. At last, the paper has introduced two new concepts of applicability degree and risk degree to assess reservoir conditions for polymer flooding and implementation risk. Taking technical, economic and risk factors into account, comprehensive potential evaluation was carried out with the predictive models of polymer flooding potential for part of reservoir blocks in Shengli oilfield in China. The evaluation results have shown that the predictive models are of higher accuracy and better extendibility, which can satisfy the demands of engineering computation application. Introduction Polymer flooding has become one of the main enhanced oil recovery methods for inshore oilfields in China. At present, enhanced oil recovery techniques such as polymer flooding and chemical combination flooding, have been widely implemented in Daqing oilfield and Shengli oilfield in China and obtained great economic and social benefits (Chang et al., 2006; Sun,2006). But as a kind of tertiary recovery method for polymer flooding itself, there must be some certain risk for its field implementation owing to intricate reservoir conditions and high cost of chemical agent. And yet, under the situation of high international oil price, were the polymer flooding applied rationally and appropriately, it would still be able to gain better economic benefits. Therefore, it is very necessary to carry out the evaluation of polymer flooding potential including technical, economic and risk aspects so as to supply guidance for polymer flooding application to reduce investment risk and enhance economic benefits.

Abstract Mechanical failure of wellbores may result in loss of zonal isolation, which is the cause of many problems, such as sustainable casing pressure, crossflows between formation zones, and leakage of fluid to surface. Pressure- and temperature-induced stresses in the cement sheath have been numerically analyzed by a number of previous investigators with sophisticated computer models. However, these investigations do not provide a practical method for predicting the maximum permissible pressure limited by the mechanical failure of cement sheath. An analytical model was derived in this work to predict the Maximum Permissible Pressure (MaxPP) in fluid injection and well stimulation. Results given by the model were verified with data from a CO2 sequestration operation. Case studies with the model suggest that if the cement placement efficiency in the annulus is 100% as detected by CBL, formation in-situ stress should be utilized to make a conservative prediction of the MaxPP. If the cement placement efficiency in the annulus is less than 100% detected by CBL, the outer radius of the cement sheath should be considered and formation pore pressure in the cap rock should be employed to make a conservative prediction of the MaxPP. Improving cement strength is not an effective means of increasing MaxPP. The MaxPP should be enhanced by maximizing the outer radius of the cement sheath through improving the cement placement efficiency. The Maximum Permissible Net Pressure is lower than the burst-pressure rating of casing, suggesting that cement sheath failure will occur before casing failure occurs in the burst condition. Therefore burst design should be carried out for cement sheath, not production casing. This paper provides engineers a practical guideline to design and apply fluid injection pressure in well stimulation and operations. Introduction Cement sheath is the most important well element for maintaining integrity of fluid-injection wells. Failure of cement sheath can cause loss of zonal isolation, resulting in not only severe operational difficulties, possibly leading to the loss of the well, but also detrimental impacts to personnel, equipment, and environments. The malfunction of cement sheath may be because of improper cementing practice involving poor hole calibration, poor casing centralization, poor selection of chemical agents for mud removal, poor matching between volume/rheologies/displacement rate of the cement train, and inappropriate cement properties. All these wrong-doing items can result in isolation defect of the cement sheath due to insufficient filling of the well annulus with cement, leaving ways for fluids to pass the cement barrier, often referred as flow-behind-pipe. The loss of zonal isolation may also be the result of secondary damage of cement sheath by the improper well operating practice including over-pressure injection, dynamic loading, thermal loading, and corrosion. This paper focuses on the issue of over-pressure injection to determine the maximum permissible pressure based on the mechanical failure of cement sheath.

Abstract Successful placement of a horizontal well requires accurate landing of the well in the right position and keep the trajectory in good pay zone to maximize the reservoir exposure. Operators face operational and economic challenges in achieving accurate geosteering due to limited seismic resolution, measure depth error (reservoir depth that is more than 5000 meters), in addition to the uncertainty in reservoir depth from time to depth conversions, lateral reservoir variability further increase the challenges. Consequently, to optimize well planning and placement for optimized productivity, it is important to minimize uncertainties in the reservoir structure and delineate lateral distribution of the sand body. The paper provides a method used to optimize horizontal well positioning that uses three-dimensional (3D) geological model to reduce structural and lateral reservoir uncertainty based on reservoir characterization. These models are used as reference during proactive trajectory adjustments and model update when landing in alignment with advance distance-to-boundary well placement technique that utlilizes azimuthal deep directional electromagnetic logging-while-drilling (LWD) technology. To improve drilling efficiency while delivering smooth trajectory control, hybrid rotary steerable drilling system (RSS) with near bit Gamma ray measurement was engaged for this project. This paper also presents the results from field tests executed in Hadexun oilfield of Tarim basin of China that demonstrates the integration of technologies to spare pilot-holes, increase the drilling penetration rate while avoiding excessive adjustments to mitigate reservoir exits. The examples describe:1. Accurately placed wells with significantly reduced probability of erroneous lateral placement along thin target layers2. Avoiding water zone in a low resistivity pay reservoir.3. Preventing sidetracks and deliver high Net to Gross (NTG).4. An average production test of almost 50% incremental above the target projection5. A 75% improvement to drilling efficiency from an average ROP in the 8 ½-in sections of 2.65 m/hr in previous wells to 4.65 m/hr.6. Securing the economics to continue developing this deep oil bearing reservoir.

Abstract Production logging in ultra-long horizontal wells has long been recognized to be extremely challenging, both in terms of data acquisition and data interpretation. This paper describes the planning, execution and lessons learnt of an incident free production/injection logging (PLT) campaign completed in twelve shallow horizontal wells – water injectors and oil producers – to support the long term reservoir management strategy of the Al Shaheen field, offshore Qatar. In this giant offshore oil field, the acquisition of even partial inflow production data is considered worthwhile. A production logging programme was therefore considered as essential. A logging campaign was undertaken in twelve wells using tractor technology as means of conveyance, in a cased hole environment. The key objectives of this campaign were to:Acquire dynamic flow data to improve the understanding of the reservoir dynamics.Identify where sub-optimum patterns can be improved to maximize ultimate recovery.Assess the tractor technology as a means of conveyance in long shallow cased horizontal wells. The campaign showed that although static data are essential in understanding the flow performance of a well, they cannot solely always explain the flow profile along the wellbore. The acquisition of dynamic data is essential to understand the well behavior. Results confirmed that in some long horizontal wells the flow profile takes place uniformly along the entire logged interval, whilst in others sub-optimum conditions such as cross flow and thief zones were identified. The paper describes how the data acquired helped to identify these latter conditions along with the repair opportunities to improve oil recovery. This campaign proved that tractor is a viable means of PLT conveyance in shallow cased horizontal wells by pushing the limits of the technology to greater depths than coiled tubing – up to 14,550 ft – with less disturbance to flow. To maximize success in future well re-entries, completion design has been reviewed in new wells, in order to make them "tractor friendly". Introduction The Al Shaheen oil field in Block 5 and Block 5 Extension, offshore Qatar, consists of a stacked sequence of low permeability carbonate and high permeability clastic reservoirs at relatively shallow depths around 3,000 ft TVD. Although the field was discovered in the mid 1970's its development commenced decades later, in 1992, when Qatar Petroleum entered into an Exploration and Production Sharing Agreement with Maersk Oil Qatar (1). Today the Al Shaheen field produces ca. 300,000 barrels of oil per day and cumulative oil production exceeds 1.4 billion barrels.

Abstract Inflow control devices (ICDs) are a proven technology of increasing reserves by passive control of the influx of fluids into the well. Experience with ICD completions shows that, although they may initially balance influx along the horizontal completion, they often do not offer the optimal solution throughout the well life due to the changing reservoir properties (pressures, fluid saturations and flow rates). Furthermore, the well completion design normally has to be designed prior to drilling the well. This, and the inevitable reservoir uncertainty, results in the ICD completion design being less efficient. A control device which adapts to the unexpected inflow performance autonomously can bring a distinctive advantage. The recently introduced Autonomous Inflow Control Devices (AICDs) favour oil rather than gas and/or water inflow. AICDs can be installed as frequently at 12 m intervals along the completion wellbore. The Autonomous Inflow Control Valve (AICV), a flow control technology that can be designed to virtually shut-off unwanted fluid inflows, takes this unwanted fluid mitigation strategy one stage further. This paper uses reservoir simulation to examine the concept of heavy oil/water production control in advanced Well Completions (AWCs) containing ICDs, AICDs and AICVs. Their performance has been analysed in a range of models to address the effects of heterogeneity, pressure losses and reservoir configuration. Both similar and very significant differences in incremental oil production were achieved between these down-hole Flow Control Devices (FCDs). This paper also developed an oil/water flow modelling workflow for reservoir and well engineering studies by quantifying the value added by the optimal use of this new, down-hole completion technology, providing preliminary completion selection guidelines. Completions that combined the widest range of proactive reactive performance, such as AICVs, were found to be the most efficient at shutting-off unwanted fluid production. Introduction to Advanced Well Completions AWCs employing ICDs provide a proven solution to several reservoir management issues by controlling the flow between the well and the reservoir along the wellbore. The technology was first introduced in the North Sea in the mid-1990's (Madsen, 1997) to drain oil via long, up to 2500 meters, horizontal wells placed in a ~ 13 meter oil rim reservoir. They improved reservoir drainage and increased oil recovery. They have since become a commonly applied technology for draining heterogeneous and heavy oil reservoirs as well as for the management of water allocation in injection wells. A wide range of commercial FCDs is available that significantly differ in their design, configuration and flow performance. FCDs currently include ICDs, Interval Control Valves and Autonomous Flow Control Devices (AFCDs). AFCDs, the latest development in flow control technology, add phase selectivity to the passive ICD's performance by autonomously creating an additional flow restriction to unwanted fluids. AFCD technology is currently in the rapid development phase with several new ideas being proposed; e.g. two new concepts employing different physical principles have been introduced in 2014 {Sang et al., 2014) and (Zeng et al., 2014}. The earliest AICDs have passed the proof of concept stage and become commercially available; while others are still in the engineering development phase (Eltazy et al., 2014).

Abstract The purpose of this paper is to introduce a stochastic seismic inversion algorithm based on Markov Chain Monte Carlo Simulation. The suggested inversion scheme generates a set of possible combinations of rock properties that can explain seismic amplitude responses in terms of lithology, pore structure and fluid variations. The result of the probabilistic seismic inversion is a seismic lithofacies catalog than can describe the elastic response of the studied subsurface interval. The main advantage of this technique is that the results consist of multiple equally probable rock properties models as an alternative to multiple elastic properties scenarios. Therefore, no post facto elastic to rock properties conversion is needed. The method might be used either in exploratory areas or hydrocarbon field development. In exploratory areas, the stochastic rock physics inversion can support the evaluation for hydrocarbon potential considering the effects of reservoir properties on seismic signatures for different geologic scenarios and physical conditions, with the prime goal of minimizing uncertainties and risk. In field development areas, stochastic seismic inversion produces multiple equally probable rock properties models that can explain the real 3D seismic response and can be used to constrain possible reservoir models used for hydrocarbon reserve estimation and reservoir production simulation. The probabilistic inversion algorithm was tested on a synthetic model that is based on real well log data. The objective of the synthetic test is to demonstrate the feasibility of the estimation of critical rock properties for hydrocarbon exploration, such as total porosity and reservoir fraction. The synthetic test results confirmed the capability of the proposed inversion technique to accurately predict the rock properties of the reservoir seismic lithofacies, even for seismically thin layers. Introduction Conventional seismic reservoir characterization (SRC) techniques were developed more than forty years ago for exploration plays where the hydrocarbon's seismic responses were relatively easy to identify. Early reservoir characterization workflows were usualy based on direct hydrocarbon indicator (DHI) identification techniques centered on post stack seismic amplitude analysis and AVO inversion. DHIs plays are usually related to shallow high porosity reservoirs with significantly lower acoustic impedance than the surrounding rocks. The associated seismic signatures of these hydrocarbon filled high porosity reservoirs can be anomalous high amplitude reflections called "bright spots". Nowadays, conventional seismic reservoir characterization techniques are becoming obsolete, since the oil industry is moving to explore areas were the hydrocarbons are located in deeper and more complex reservoirs. These new hydrocarbon plays are characterized by low porosity and low permeability reservoirs with near to undetectable pore fluid response. It means that the future seismic reservoir caracterization goal is to predict rock properties such as porosity, lithology and rock fabric of compacted and cemented porous rock. The second more important SRC challenge is to improve the seismic vertical resolution. Currently, seismic inversion resolution is still low for the new exploration/development challenges and improvement of seismic derived elastic parameters is paramount for the application of reservoir properties prediction. Techniques such as stochastic inversion have been initially developed in an attempt to obtain from seismic data quantitative information about subsurface rock properties on a very detailed scale. The goal of this paper is to introduce an inversion technique based on Markov Chain Monte Carlo simulation that can be implemented in a stochastic petrophysical inversion scheme. The stochastic seismic inversion's objective is to produce a set of equiprobable rock properties volumes that can describe the elastic seismic response of the studied interval and their associated uncertainties. The main advantage of this petrophysical inversion technique is that the results are multiple equally probable rock properties models instead of multiple elastic properties scenarios. Therefore, no elastic to rock properties conversion is needed after the inversion is performed. The method might be used either in exploratory or development areas.

Abstract Accurate and timely well rate tests ensure prompt operating decisions and effective reservoir management, especially for shut-off of any unwanted fluid. A conventional well testing system typically employing a two-phase separator and single-phase flow meters has widely gained industrial acceptance in highly productive oil fields. Because of full range water cut capability, immunity to fluid compositional change and flow disturbances, no wearing parts and high measurement accuracy, a Coriolis flow meter as a single-phase flow meter gained popular installation in such conventional well testing systems over the last few decades. Positive results had been produced from such Coriolis flow meters in one of Saudi Aramco's operating oil fields over the last decade. Consequently, as a result of invasion of gas cap gas, the existing testing facility could not provide very reliable well testing results recently in this oil field. Testing deficiency significantly impacted the reservoir management decisions for effective shut off of excessive gas production in some oil producers. Intensive well rate testing campaigns using different technologies, including multiphase flow meters (MPFMs) were conducted. The analysis of testing results revealed that some factors greatly impact the measurement accuracy from a Coriolis flow meter, which primarily led to the testing deficiency in this field. Discussed and analyzed in this paper is how the quality of the testing data is affected by the influential variables, testing facility configuration, and operating process. The root causes of testing deficiency were identified and specific solutions to solve those issues proposed. Innovative flow calculation formulae are developed to rectify the reported testing data and verified by other source testing data. As a result, testing efficiency was improved by 30%~60% by the existing testing facilities in this field. Also described in this paper are lessons learned, which will enrich the technical knowledge base. As a result of this work, an approximate $3 million investment could be avoided to replace the existing 30 plus testing facilities with new MPFMs. Introduction Well testing always provides critical decision making information at every stage of an oil field's development life. At the early stage during the oil exploration, well testing helps the engineers to confirm whether the underground hydrocarbon reserve can be economically tapped using whatever technology is available in the market and to prove the estimated reserves. During the normal development of a field or a reservoir, well testing provides petroleum engineers with insight into the production potential of the reservoir and with the physical evidence of well conditions. Unexpected changes, such as extraneous water or gas production may signal well or reservoir problems. Abnormal production declines may be caused by artificial lift problems, scale buildup in the perforations, etc. All information provided by well testing enables early detection of any wellbore problems and allows the engineer to take remedial actions quickly, to ensure optimum production from a well, and to have more confidence in production changes as a result of well workovers, wellbore stimulation or treatment. In brief, accurate and timely well testing information always plays a critical role in reserve estimation, production forecasting, production optimization, capital and operational decisions during the entire development life of a reservoir.

Abstract Flow assurance is a critical problem in the oil and gas industry, as an increasing number of wells are drilled in deep water and ultra-deep water environments. High pressures and temperatures as low as 2° C in these environments hinder flow of hydrocarbon-based fluids by formation of methane hydrate and wax. Commonly used methods for flow assurance in flowlines are chemical injection and direct electric heating which face several limitations. In this paper, an application to use superparamagnetic nanoparticle-based heating for flow assurance, in the form of a magnetic nanopaint is presented. Superparamagnetic nanoparticle-based heating has been extensively researched in the biomedical industry for cancer treatment by hyperthermia. Superparamagnetic nanoparticles in dispersions generate heat by application of an oscillating magnetic field as explained by Neel's relaxation theory. In our application, superparamagnetic Fe3O4 nanoparticles are embedded in a thin layer of cured epoxy termed 'nanopaint'. This nanopaint coating on the internal surface of subsea flowlines could generate heat and thus prevent formation of methane hydrates and wax. In this paper, parameters affecting heating performance of superparamagnetic nanoparticles such as particle size, and magnetic field and frequency are discussed. Rigorous characterization of nanoparticles and nanopaint performed using VSM, TEM etc., is used to quantify heating performance and optimize it. Heating performance of two samples of Fe3O4 nanoparticles varying in size distribution is evaluated in batch experiments and compared to Neel's relaxation theory. Performance of nanopaint to heat static/batch fluids and flowing fluids is evaluated. Heating performance of superparamagnetic nanoparticles in dispersions and in nanopaint is found to be similar and so it is concluded that Neel's relaxation theory is applicable to nanopaint. Heating performance of nanopaint is flow experiment is found to be better than in batch experiments by a factor greater than 5. 1. Introduction Flow assurance is the ability to transport hydrocarbon-based fluids economically and safely from the reservoir to production facilities, over the life of the field. With increasing oil and gas production from deep-water and ultra-deep water wells, flow assurance has become a critical problem for the oil and gas industry. Subsea wells are at greater risk of deposit formation due to low temperatures and high pressures in deep water environments. Methane hydrate formation and wax deposition severely limit production rates, pose safety concerns and may also result in the shutdown of the well. Hence various methods are employed for remediation and prevention of flow assurance problems, primarily relying on the principles of temperature increase, pressure reduction or mechanical removal. These methods include use of pigging solutions, chemical additive injection, SGN (nitrogen steam generation) process, direct electric heating, heated pipe-in-pipe (Hpip) solutions and have been previously summarized in [1]. Commonly used methods in the industry are chemical injection and direct electric heating. In chemical injection, a glycol usually methanol is injected into the pipeline to lower the hydrate formation temperature. However, high costs and concentration limits imposed by quality control limit their usage. In direct electric heating, electricity is forced through tracer cables laid along the length of the flowline. Temperature can be controlled by varying the power input to the system and variable heating rates can be obtained. However, there is risk of electricity leakage and component failure due to excessive heating. In this paper, we use superparamagnetic nanoparticle-based heating to address the issue of flow assurance.

Abstract During the last decades nanotechnology has proven to be applicable to a variety of different technological and research areas such as material design, biomedicine and electronics. The cross disciplinary research during the past decade has also revealed that nanotechnology possesses great promise for enhanced oil recovery applications. Nanoparticles are small particles characterized by a diameter of 1–1000 nm and a very large area-to-volume ratio where the surface can be modified by conjugation or grafting to various kinds of molecules. Moreover, the material of the nanoparticle core can be selected to obtain specific physical properties. One example here of is to design nanoparticles of a super-paramagnetic material to enable flow manipulation via an external magnetic field. The fact that ultra-small nanoparticles can flow through narrow pores and pore-throats and that core/surface properties can be modified for a specific purpose via standard chemistry, makes them ideal candidates for various EOR applications. Consequently, research related hereto has been steadily intensified. In the present paper we present a thorough review of the current research and development within the field of nanotechnology-based EOR, where nanoparticles are used to target various aspects of EOR processes. For instance nanoparticle-based EOR approaches have been developed to promote wettability alteration, viscosity reduction of oil, stabilization of foam or emulsions and interfacial tension reduction – in some cases involving application of an external electric or magnetic field. Nanoparticles have likewise been developed for flow assurance and well performance improvement by e.g. inhibiting hydrate and wax deposition. Finally, nanoparticles have shown potential in upstream applications and reservoir characterization (e.g. nano sensors). Based on an extensive, critical and in-depth review of technical papers we will discuss opportunities and challenges, e.g. related to environmental issues, associated with nanoparticle-based EOR applications for the oil and gas industry. Moreover, we will provide a practical framework for designing tailor-made nanoparticles for targeted applications for the oil and gas industry by means of surface chemistry and superparamagnetic properties of nanoparticles. Introduction Innovation in oil exploration and enhanced oil recovery (EOR) technologies will be required to meet future demand of hydrocarbon fuels, and hence the O&G industry will inevitably have to focus on development of new technologies to increase the oil recovery of currently producing reservoirs as well as unconventional oil and gas resources – via research and technological innovation. Nanotechnology and nanoparticles provides a promising approach to such innovation. Nanotechnology and applications of nanoparticles have revolutionized different sciences and industries and it possesses significant potential in the oil and gas industry as well in the fields of EOR, exploration, drilling fluid design, molecular separation, refining, water treatment etc. which we will describe below. The significant advantage of nanoparticles is that they can be tailor-made in a flexible manner using combinatorial chemical approaches and provides therefore an approach to transcend the current EOR technology. In this paper we will describe different applications of NPs and notably also present concepts developed at Maersk Oil Research and Technology Centre based on which numerous patent applications have been filed.

Abstract Telok is a gas field development in the Malay Basin, off the coast of Terengganu in Peninsular Malaysia. This paper discusses the program learnings and operational improvements captured while completing eight new wells in 2012 and 2013. The primary reservoirs targeted in the field require sand control, specifically frac pack technology, due to the high fines content. Long frac pack intervals (up to 60m) at inclination up to 75 degrees were designed using alternative path screen technology to maximize reservoir exposure as well as to obtain high injection rates and proppant concentrations during frac pack operations. This resulted in relatively high treating pressure. The frac pack operation on the second well in the campaign presented operational challenges. Several top-up jobs were performed but no screenout indication was observed even though proppant pumped downhole exceeded the initial planned volumes by 20klbs. Reconfirmation stresses showed very low blank fill / insufficient blank coverage. The final top-up job was performed as a circulating pack instead of a frac pack, successfully packing the casing/screen annulus. Further analysis of the frac pack operation identified the shallow vertical depth of the sand and the associated low overburden stress as a key root cause of the issue. The shallow vertical depth of the sand resulted in the injection pressure exceeding overburden stress, creating a horizontal fracture. It was concluded that the frac pack treatments have to be optimized by controlling net pressure and fracture geometry. Several lessons were learned and improvements were developed from this well that were applied throughout the remaining campaign and will be discussed further in the paper. In order to overcome the challenge of high treating pressure associated with long sand control intervals with low overburden stress due to the shallow vertical depth, improvements were implemented such as managing the standoff from the top and bottom of the sand interval to the shale and optimizing gel loading in the frac pack fluid to increase fluid leak off. Introduction Telok field is a faulted, east-west trending anticline in the Formation A reservoir. The major reservoir in Telok is the Formation A sands, containing dry non-associated gas (NAG). The Formation A reservoir is located at approximately 700–800m TVDss and is laterally extensive across Telok, Tabu, and Guntong fields. Minor non-associated gas (NAG) reservoirs are the Formation B group and Formation C group sandstones. Formation B and C reservoirs are located between 1,100 to 1,900m TVDss. Sand control was performed for the Formation A and B-1 reservoirs based on offset well's performance and sand screening evaluation completed based on data from a Telok exploration well. Sand production was observed during production tests in the exploration wells drilled in the Formation A reservoir. Sieve analysis conducted on core material collected from the exploration wells, together with sand strength modeling work, confirmed that the Formation A sand is friable and would produce sand on initial completion with a high percentage of fines.

Abstract ExxonMobil and its Canadian affiliate Imperial Oil Resources are pursuing an integrated research program targeted at developing the next generation of heavy oil recovery processes which utilize light hydrocarbon solvents in conjunction with steam or as an alternative to steam-only processes to mobilize the in-situ heavy oil. The key benefits of employing solvent are improved economics and increased recovery from resource that is impractical with steam-only processes, improved environmental performance, particularly reduced greenhouse gas emissions and reduced water use. A suite of field trials, pilots and commercial applications have been operating over the past several years at Imperial Oil's Cold Lake field in Alberta, Canada. These have included both solvent-assisted and solvent-only field trials. Collectively, the results of these trials show that solvent recovery processes for heavy oil are technically viable and have considerable commercial potential. This paper summarizes the dimensions of the integrated research program that have been key to delivering the successful results to date. Simulation, laboratory testing and physical modelling with a focus on scaling to the field have been employed extensively prior to field testing. Short-term, relatively low cost field trials have been utilized to calibrate models prior to more costly, longer term pilots with dedicated facilities. Extensive field characterization has been conducted prior to final site selection and pilot operation. Integrated operational and surveillance plans have been employed to ensure measurable and reliable field performance data is acquired that can be used to calibrate and validate simulation performance. Finally, learnings from this integrated research program can be more broadly applied to the commercialization of other EOR processes and the research and development processes leading up to the decision to execute a major pilot. Introduction Thermal recovery processes including steam flooding, cyclic steam stimulation (CSS) and steam-assisted gravity drainage (SAGD) are among the most broadly applied and commercially successful enhanced oil recovery (EOR) processes. In recent years there has been considerable growth in production utilizing these methods in the Canadian oil sands deposits which are primarily located in the Cold Lake and Athabasca regions of Alberta. These processes can be very efficient and economic when applied in thick, high porosity, high permeability reservoir deposits. However, significant volumes of natural gas are required to generate the steam used in these processes and associated with the steam generation are greenhouse gas (GHG) emissions. There are strong economic, technical and environmental drivers to develop enhanced thermal recovery processes that reduce steam utilization, enable more efficient recovery from lower quality resources and improve environmental performance. The enhanced heavy oil recovery processes described in this paper target these challenges. An overview of this integrated technology development program was provided previously by Boone et al1. This paper reports on the continued successful development in subsequent years and expands on some of the key factors for success. Those factors include:A long term dedicated research program in the area of heavy oil recoveryDisciplined application of a gated research processA host field where pilots and field trials are strongly supported by management and competently supported by skilled and experienced operating personnel

Abstract The Changqing field is one of the largest fields in China, yet it is characterized by low permeability, low initial pressure, and low reservoir quality. During the past few years, technological advancements within the oil industry, horizontal drilling, and hydraulic fracture stimulation have helped create a development boom in this field, with total production of barrel of oil equivalence (BOE) reaching 50 million tons in 2013. Located in the Ordos basin of China, the primary pay formation of the Changqing field is Triassic, which features a complicated sedimentary system. 72.8% of reservoirs in the Changqing field have permeability lower than 1.0 md. Although it was apparent that all of these wells would require fracture treatments to help achieve optimum production, it was difficult to identify a routine treatment design or fracturing strategy to extend to all of the reservoirs because the Changqing field has 19 oilfields and three gas fields stretching over five provinces. The sediment source of the pay formation varies in terms of direction and lithology, and all of the sedimentary systems vary from fan delta to braided stream delta systems. To maximize well production, it is necessary to analyze the differences among these fields and identify the most favorable fracture treatment design for each field. Microseismic mapping has proven to be a valuable technology for assessing and optimizing the fracture treatment by describing fracture geometry. This paper introduces a real-time microseismic mapping project conducted on a multistage fracture treatment in a specific tight sand reservoir of Changqing; during this project, a quantifying relationship between the fracture treatment parameters and stimulated reservoir volume (SRV) was realized, enabling stimulation optimization in this area. This paper details the microseismic mapping acquisition, hydraulic fracture symmetry, practical drainage pattern, evaluation of the fracture treatment parameters, and perforation strategy that impact fracture geometry and SRV as well as optimization in this particular tight sand reservoir. Introduction Located in northern middle China, the Ordos basin (Fig. 1) is the second largest depositional basin, covering an aerial extent of approximately 370,000 square kilometers, stretching across the Shaanxi, Gansu, Shanxi, Ningxia, and Inner Mongolia, with original oil in place (OOIP) of approximately 8.6 billion tons. The Ordos basin is a superimposed basin having experienced multiple tectonic movements. The stratigraphic fill of the Ordos basin is composed of numerous facies. These types vary between Carbonate Platform, Clastic sedimentary of Paleozoic, fluvial, delta, and lacustrine of Mesozoic; its total thickness is approximately 5000m. In the Ordos basin, hydrocarbon contribution formations of Triassic and Jurassic produce oil; whereas, Permo-Carboniferous and Ordovician produce gas. Across the entire board of the basin, oil reservoirs are distributed in the southern portion, while gas reservoirs are abundant in the northern part. Because of complex tectonics characteristics and low permeability, reaching its current total production of BOE of 50 million tons per year proved overwhelmingly difficult. Before the 1950s, it took 50 years to achieve production of 2,000 tons per year; it then took another 20 years to achieve production reaching 20,000 tons. Even up to the year 2000, production was only 7.5 million tons per year. In the last 10 years, as conventional sources of oil and gas have declined, operators have been driven to explore unconventional resources globally, and the Changqing field had made astonishing progress during this period.

Abstract Y is a giant carbonate oilfield with low permeability and mid-high porosity, of which the characteristic is extensive plane distribution and many series of oil-zones in the longitudinal direction. The service contract required a large scale capacity construction with nearly 30 million ton and long stable production period above 13 years, but provided a low remuneration fee with only 1.4$/bbl. Full oilfield integrated optimization is crucial to achieve high effective development and enhance economic benefit. In this paper, the procedure of research on integrated development optimization was elaborated. The paper established new productivity model with oil-water two phase to accurately evaluate oil well productivity. Depletion mode and zones combination were demonstrated and optimized through core experiments and numerical simulation. The sensitivity studies of well types, well patterns and well spacings were carried out through modelling and empirical formula method. Multifactor analysis was completed with surface engineering and external oil-gas transportation capacity as important factors, and development strategy of rapid productivity construction and rolling development is put forward. Depletion plan for each reservoir has been also optimized based on full reservoir simulation modelling. The recommended depletion plan has been implemented in the oilfield development, of which productivity coincidence rate was nearly 100%, first stage productivity capacity with 5 million ton has been set up in 2012, and IRR increased from 9% to above 13%. Introduction Y is a giant carbonate oilfield in Iraq, with huge oil area, massive geological reserves, multiple zones in the vertical direction, varied characteristics in the lateral direction and high well productivity. These carbonate reservoirs have low natural energy and reservoir pressure declines rapidly when depletion drive is adopted, resulting in low recovery. Development optimization is needed, proper measures should be taken to supplement energy, and economic and effective technical plan should be proposed to improve the production rate within contract period and get a high and stable production. Zones are combined and optimal development mode is selected according to the policy in host country of resources and requirement in production and services contract. The type of well and well pattern is determined based on the underground and surface is integrated and optimized. The goal is to maximize the potential of each reservoir and achieve overall development of the oilfield and improve the production rapidly. The key point in economic and efficient development is to improve well production significantly and keep the well production stable for a relative long period of time, with a low profit of 1.4$/bbld in the contract. In order to improve production by dozens of million tons and get a stable production in the long term in Y oilfield, this paper optimizes the overall development plan to minimize the early investment and to achieve progressive development of the oilfiled and maximize the economic benefit. The production of 5 million tons in the first stage, which was started ahead of schedule, and the productivity of 10 million tons, which was achieved in the second stage, provides references and instruction on how to develop similar huge carbonate oilfield.