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With the decreasing price of oil nowadays, the need to develop techniques to reduce operational costs in a field is inevitable. Formation water is a by-product obtained during oil production which is produced is produced in higher quantities than hydrocarbon. This is a major concern for oil and gas industry as separating, treating and reinjecting of the produced water into the reservoir formation requires a large amount of energy, money and time. This paper proposes a new technique for downhole separation of oil and water using a tubular centrifuge which can be integrated of the casing or the tubing string. This centrifugal downhole oil/water separator (CDOWS) will introduce the feed to a large centrifugal force which will separate both fluids based on density differences. The technology is designed for different well configurations satisfying several conditions in the industry. This paper shows and tests the model using Computational fluid dynamics (CFD) study for different designs and configurations. To validate this process in a downhole configuration, a computational fluid dynamics (CFD) study is conducted on a CAD model which was designed using a 3D modeling software. The study investigates the separation efficiency using various diameters, RPMs of the CDOWS as well as different flow rates and water cut. Furthermore, different possible designs are considered in this study. The results are then used to optimize the design of such tool in order to produce a physical model.

Managed Pressure Drilling (MPD) and wireline logging under pressure were both successfully employed while drilling a pre salt, exploration well offshore Angola. The well was drilled with a 6th generation drillship using an integrated, Below Tension Ring (BTR) MPD package with the drilling contractor's Riser Gas Handler (RGH). Drilling exploration wells in pre-salt formations presents a plethora of challenges, with severe drilling fluid losses, often due to the natural fractures and/or vugular porosity encountered. This paper discusses the challenges faced drilling the desired hole section, managing severe losses, a downhole cross flow regime and high surface gas levels. Concern for exiting the salt section and taking total losses in a possible vugular carbonate is addressed and the contingent plans developed are discussed. Fluid loss management was critical and discussion is provided on the remediation methods used to limit losses. The paper describes how considerable gas was detected, handled and eventually controlled using the available surface equipment and methodology for preventing continuous gas influx and prolonged, off bottom circulating for removing the gas from the wellbore. Extensive wireline logging was completed, both at an intermediate stage and at total depth (TD). Most of the wireline logging was performed under minimal pressure with a logging adaptor installed in the rotating control device (RCD), 9 5/8" casing shooting nipple back to surface and wireline pressure control equipment (WPCE). The paper concludes with a series of key lessons learned that can be taken from this experience and considered when planning similar deep water, pre-salt exploration wells with the use of MPD equipment.

Many people believe in the benefits of incorporating Managed Pressure Drilling (MPD) into well planning, which has been done onshore for a long time. In recent years this technology has been transferred to offshore drilling vessels. However, there appears to be some hesitation in widely implementing MPD solutions offshore, due most likely to perceptions regarding complexity and cost of integration. This paper has been written to communcate the scope associated with implementing a Controlled Mud Level (CML) MPD technology onto an offshore drilling vessel in order to allow Operators and Rig Contractors to evaluate the level of complexity involved. This paper emphasizes that the technology has now been integrated onto several rigs, allowing the CML provider, Rig Contractors and Operators to work out best practices for technology implementation. Integration of a CML system is now accomplished with standard products, a well-defined scope and experience-based understanding of what is required.

The focus of this paper is on the benefits of model-based control for performance of pressure control and how to enhance robustness against changes in system dynamics by use of adaptive control in managed pressure drilling (MPD) operations. In this work, we present the advantages and disadvantages with adaptive model based control for MPD operations, by implementation of a choke pressure controller. The paper will show that model-based control enables pressure control down to fully closed choke and trapping pressure without a backpressure pump. Moreover, by adding adaption to the model-based controller it is made robust to changing well parameters, recovering control performance. This is part of a pre-study and preparation for flow loop testing in Abu Dhabi Winter 2016, where performance and robustness of the controller is tested for gas influx and a variety of standpipe pump rates and pressure ranges. The purpose of the flow loop testing is to verify that the controller gives satisfactory performance and is the final test stage before the technology is ready for field use.

Based on experiences with the Controlled Mud Level (CML) system ECD-Management (ECD-M) in the Gulf of Mexico (GoM) in 2014 and 2015, this paper outlines how the reduced riser level was applied to improve kick detection and to reduce drilling risks associated with downhole pressure constraints. CML is a Managed Pressure Drilling (MPD) technology, but it is not only about Constant Bottom Hole Pressure (CBHP). The paper will cover the authors' learning curve from the first to the 4th well. The main focus during the first well was to make everything work and to train the personnel on the rig. The riser level was only reduced by about 150 feet and the ECD-M system was mainly used for improved kick detection by using the riser as a trip tank. Several kick drills were performed with good results showing how the drill crew was able to detect influxes even earlier with the new CML parameters. The use in the second well was extended by mitigating salt creep in the salt section, CBHP during salt exit and reducing hydrostatic head during a cement operation. Further experiences were gained during the last two wells, even though one major new component failed during commissioning. Other potential applications will also be described. The paper will describe the planning of riser levels and controller modes together with the usual drilling parameters mud weight, flow rate, ROP, etc. using hydraulic simulations and pore and fracture gradients taking the different constraints and risk into consideration.

Pilots are widely used for the purpose of gathering valuable information about performance and practical challenges of implementing a particular CEOR process in a given field (Adibhatla and Wattenbarger, 2009; Cheng et al., 2012). A critical step in proper design and optimization of any CEOR process, in full field or pilot scale, is appropriate and precise numerical simulations. Many considerations need to be taken into account for such simulations. Addition of chemical species to the material balance equations alongside finer resolution requirements for CEOR simulations compared to waterfloods (WF), often make it impractical to run full field CEOR simulations to the required accuracy. Massively parallel computing, dynamic local grid refinement and sector modeling have been used with varying success, of which sector modeling is the most common. Sector models, by their very definition, are also naturally suited for modeling of pilots. The art of sector modeling needs mastering a few important steps such as: appropriate selection of the sector model extent, details on carving it out of the Full Field Model (FFM), populating it with proper petrophysical and fluid properties, initializing it to correct initial conditions and optimizing its boundary conditions. On top of that, choice of optimum grid size for proper trade-off of simulation run times and accuracy needs to be considered. This paper presents a case study for appropriate simulation of a CEOR pilot within Chevron. The candidate has a waterflood history matched FFM. This model is used to generate a sector model for the CEOR pilot area. This paper outlines how the extent of the sector model and all the regions in communication with the Area of Interest (AOI) is decided. It also discusses proper initialization and optimization of the boundary conditions of the sector model along with its appropriate refinement and grid optimization. Proper CEOR simulations on the final optimized sector model and sensitivity analysis are also presented. The challenges, lessons learned and best practices are shared and important considerations for adequate simulation of CEOR processes are outlined.

Declining oil production and increasing water cut in mature fields highlight the need for improved conformance control. Here we report on a successful in-depth water diversion treatment using sodium silicate to increase oil recovery at the Snorre field, offshore Norway, utilizing a new operational concept of using a stimulation vessel as a platform for the large-scale injection into a subsea well. A custom modified 35,000 DWT shuttle tanker was employed for the field pilot. This paper describes the vessel preparations and the large-scale interwell silicate injection operation. The operational aspects of the large-scale interwell silicate injection include; identification of injection vessel requirements, major vessel modifications, chemical logistic, general logistics to site, major equipment set-up on vessel, subsea connection, mixing and pumping schedules, onsite QC, and real time monitoring. Experience from these operations and lessons learned are included in this paper. After the injection of approximately 400,000 Sm3 (113,000 Sm3 preflush, followed by 240,000 Sm3 of sodium silicate gelant and 49,000 Sm3 of postflush fluid) at injection rates up to 4,000 Sm3/d, the injection from the vessel was stopped and the well was put on regular seawater injection. Following more than two years of regular production, transient pressure measurements, tracer testing and water cut data are presented from the ongoing comprehensive data acquisition program. These results demonstrate clearly the achieved in-depth flow diversion through a delayed breakthrough of injected tracers and lower water cut in the relevant production well.

Polymer gels are increasingly applied to improve sweep efficiency of different IOR/EOR recovery processes. Three in-situ polymer gel systems including bulk gels, colloidal dispersion gels, and weak gels are often used to mitigate water production caused by reservoir heterogeneity and unfavorable mobility ratio of oil and injected fluids. Selecting the most appropriate gel system is a key component for a successful conformance improvement treatment. Screening criteria in terms of reservoir and fluid characteristics have been widely used to identify potential technologies for a specific reservoir. Despite the large number of polymer gel projects, only five, limited-parameters, single-agent criteria or surveys have been sporadically accomplished that suffer from many deficiencies and drawbacks. This paper presents the first complete applicability guidelines for gel technologies based on their field implementations in injection wells from 1978 to 2015. The data set includes 111 cases histories compiled mainly from SPE papers and U.S. Department of Energy reports. We extracted missing data from some public EOR databases and detected potential outliers by two approaches to ensure data quality. Finally, for each parameter, we evaluated project and treatment frequency distributions and applicability ranges based on successful projects. Extensive comparisons of the developed applicability criteria with the previous surveillance studies are provided and differences are discussed in details as well. In addition to the parameters that are considered for other EOR technologies, we identified that the applicability evaluations of polymer gels should incorporate the parameters that depict roots and characteristics of conformance issues. The present applicability criteria comprise 16 quantitative parameters including permeability variation, mobility ratio, and three production-related aspects. Application guidelines were established for organically crosslinked bulk gels for the first time, and many experts' opinions in the previous criteria were replaced by detailed property evaluations. In addition, we identified that the applicability criteria of some parameters are considerably influenced by lithology and formation types, and thus, their data were analyzed according to these characteristics. Besides their comprehensiveness of all necessary screening parameters, the novelty of the new criteria lies in their ability to self-check the established validity limits for the screening parameters which resulted from the inclusion and simultaneous evaluation of the project and treatment frequencies.

Enhanced oil recovery (EOR) processes are regarded as important methods to recover remaining oil after primary and secondary recovery. It is important to select the most appropriate EOR process among the possible techniques for a candidate reservoir. Therefore, EOR screening criteria have been constructed using available EOR data sets and serve as the first step to compare the suitability of each EOR method for a particular reservoir. Most screening criteria for polymer flooding are based on data sets from EOR surveys published biannually by the Oil & Gas Journal. These surveys missed significant polymer flooding parameters such as formation water salinity and hardness, polymer types and molecular weight, polymer concentration, reservoir heterogeneity, and so on. All of these topics are covered in this paper with data from relevant literature and records provided by oil companies in China. Polymer flooding has been widely applied in China for over 20 years and a large number of pilot and field projects have been conducted. These projects include important information to quantify the development of polymer flooding as an EOR method. Nevertheless, most of them have been published in Chinese, and are not accessible to the global research community due to the language barrier. This paper represents an effort to collect all relevant information of polymer flooding from available Chinese publications and reports from all of the major oil companies in China. The primary objectives of this survey is to reveal EOR advances, to trace the development of the polymer flooding EOR methodology in China, and to benefit EOR worldwide. This project collected information on 55 polymer flooding projects after reviewing nearly 200 publications in Chinese, including 31 pilot projects and 24 field projects from 1991 to 2014. A data set was constructed by collecting all relevant information for polymer flooding. Statistical analyses and graphical methods were used to analyze the whole data set. Box plots combined with violin plots were used to show the distribution and the range of each parameter. By defining and calculating lower and upper limits in box plots, special projects were identified and explained. Scatter plots, which show multiple parameters in one plot, were used to identify significant relationships among different parameters, especially for dependent parameters. This method overcomes some disadvantages of the range method, which is traditionally used for EOR screening. For example, using polymers with high concentration in low salinity reservoirs can lead to higher incremental oil recovery than in high salinity ones, and lower permeability usually correlates with the use of polymers with lower molecular weight. However, the traditional range method cannot show this relationship. Finally, comprehensive screening criteria for polymer flooding were updated based on information revealed in the field application projects.

Progressive Cavity Pumps (PCPs), if properly sized, can greatly improve a well's deliverability and run-life. As a result, PCP sizing for a large number of wells can be instrumental in a production optimization program. This paper presents a quick look methodology adopted in the Bhagyam field to better understand PCP system performance and to accurately predict pump deliverability under a wide range of downhole conditions for more than a hundred wells. Using nodal analysis, this paper presents the procedure used to select optimum pump size and well fluid rates from well inflow and outflow performance. The paper also presents a correction factor for the effect of viscosity on pump performance and uses the corrected pump performance curves to model the expected liquid rate from a well. The solutions obtained with the analyses have been validated against actual Bhagyam well test data and have proved to be fairly consistent. This procedure has not only been a useful tool for pump selection and performance monitoring but has also made a significant business impact in terms of incremental oil gain.The methodology quickly provides reasonably accurate solutions for pump selection and allows evaluation of real time pump parameters to optimize PCP under varying field conditions.

This paper reviews the recently concluded first Weatherford Rotating Control Diverter application to a Loss and Kick scenario well in the Murree formation in Pakistan. The Murree formation in that area is considered as one of the toughest hurdle in reaching the target depths. The most common problems that are observed in this formation are loss and kick situations, which lead to conventional well control and then the hole tightening issues. In this well the client is having the same problems but in more adverse manner. There was a loss zone below and a gain zone above. They cemented the drilled portion of loss zone but whenever they try to drill further; got loss and then kick. Too much time was spent in controlling the well and then the well got tight and sometimes the string also got stuck. The major scope of work for this well with the use of Rotating Control Diverter is to divert the flow from the well, strip out of hole even during well flowing conditions and keeping surface back pressure whenever required. A brief history of the Flow Diversion Technique using Weatherford RCD is provided in this paper which is followed by a discussion of the benefits added by the RCD in minimizing the NPT associated with such drilling hazards. The RCD successfully diverted the gain/kick got after having complete or partial loss situations. The RCD helped to strip out of hole even having continuous well flowing conditions. In conventional techniques this is not possible to POOH without controlling the well. This saved time as well as saved the drill string from being got stuck or packed off. The squeezing jobs were also aided by the use of RCD as after pumping the pill; the string was pulled out without releasing the applied pressure. All these advantages lead to the completion of the well in a safe and efficient fashion. In Summary; applications of innovative and advanced technologies helped operator to perform the drilling operation fruitfully in this challenging formation in Pakistan. This paper reviews the process that was used to identify, plan, and implement this pioneering thought. The purpose of this paper is to highlight all the benefits and lessons learnt while applying this state of the art technology. This will help many in the industry to implement and design such innovative techniques and robust equipment for the mitigating drilling hazards.

Hydrates and waxes are the main flow assurance threats in the development of deepwater fields. Prevention of wax deposition is a key component of preferred subsea deepwater system design. This paper discusses the challenges associated during the design of a deepwater field in the Indian offshore and the means of mitigation during the entire operating envelop. The deepwater discoveries for development lie in 400 – 800 mts of water depth, spread over 25 km with a recoverable volume of around 30 MMt of O+OE of gas and are envisaged to be tied back to a centrally located FPSO for handling and further evacuation. The fluid properties are very severe with high WAT and pour point. Limited case histories exist for deepwater fields developed with similar fluid properties. Low ambient temperature and poor fluid properties aggravate the likelihood of wax deposition and hydrate formtation. Based on the fluid characterization data for the development, issues due to wax deposition are expected. The present means of preventing flow assurance issues is through use of passive insulation, active heating or by chemically altering the thermodynamic behaviour. Various means were analysed either alone or in combination to arrive at an effective wax management strategy to surmount the deepwater barrier and to convert resources into production. The use of dual pipe-in-pipe system with high performing insulating material, combined with cluster based development aid in fluids arriving at temperatures above WAT over major part of the profile period. During the transient conditions wax management is envisaged through flooding of the well jumpers with chemicals and displacement of flowline contents, after the no touch time. Since the fields are to be developed on a fast track basis, limited data poses challenges in design. This paper highlights the flow assurance challenges that were studied to develop suitable wax and hydrate management during operational phase while maintaining the flexibility to accommodate modifications after actual fluid property data is available. The wax and hydrate management strategy proposed in this paper would facilitate in addressing a unique challenge of handling high WAT and pour point crudes with limited fluid data specifically in deepwater environment.

An appraisal well in the KG Onshore Block (a joint venture of Cairn India Ltd and ONGC) has provided key engineering and operational learning's. The objective of this well was to appraise two separate low permeability reservoirs (~ 0.1md) which are ~4300m deep and falls under HPHT conditions. Due to their low permeability; hydraulic fracturing was necessary to verify the production potential of these reservoirs. To cater this, the discovery well was re-designed and sidetracked so that it could handle the expected fracturing loads. Hydraulic fractures (~387,000 lbs of Proppant); biggest in terms of proppant placed in any single stage in India, were executed and then the well was completed with slim-hole selective completion in challenging underbalanced conditions to test these reservoirs selectively. This paper primarily talks about the key constraints while planning and designing this well and then deals in detail on the learnings while executing this unique completion operation. Details on the fracturing design were already covered by Barasia et al. in SPE-171421-MS. The paper concludes with production results and the key reasons which led to ~7 fold increase with respect to previous appraisal well, as observed while production testing.

Subsea pipelines carrying high temperature and high pressure hydrocarbon fluids are prone to failure due to global buckling. The design of such pipeline should essentially consider the effect of seabed profile (flat or uneven), types of soil on the mudline (sand or clay) and pipeline route layout. To check pipeline integrity a two step approach has been applied. In the first step, buckling susceptibility is estimated based on empirical formulation provided in research papers and code. In the next step, the buckle prone pipeline has been studied through a rigorous approach, where Finite Element Analysis tool is utilized to simulate the actual in-place scenario i.e. considering the pipeline as installed on the uneven sea bed and the effect of pipe soil interaction. It is observed that the assumptions applied in empirical formulation result in over conservative design. Such designs have a cascading impact on the material requirement, offshore construction time and overall project cost. The FEA approach is effectively utilised to have an optimized boundary condition i.e. by allowing actual seabed modelling based on bathymetry data at close intervals, pipeline layout and a refined pipe soil contact modelling. This paper focuses on the application of research work and code guideline for determination of susceptibility of high pressure high temperature submarine pipeline to lateral buckling and application of Finite Element Analysis (FEA) methods to assess the integrity of the pipeline system for the maximum operating condition. FE Approach can be effectively utilized to simulate the actual pipeline behaviour on seabed. It also provides the necessary design inputs for designing pipeline buckle mitigation solutions.

An operator in India desired two modular, skid-mounted, plug-and-play quick production facilities (QPF) with the capacity for quick relocation and commissioning within multiple fields. This paper discusses the successful solution presented by the service company using an economic, flexible, and reliable QPF model. It also discusses challenges related to flow assurance, limited infrastructure, and compliance with the India Directorate General of Mines Safety (DGMS) challenges. The QPF model consists of process skids, utility and storage systems, interconnected piping, data acquisition (DAQ), and a power distribution system. The well flowline is routed through an indirect water bath heater (IWBH) and three-phase separator. Oil from the separator transfers to the export oil storage tank and loading gantry. Water travels to the evaporation pond through a skimmer tank, and gas is transferred to the burn pit through a knockout drum (KOD). Liquid accumulated in the KOD is transferred to the storage tank. A closed drain maintenance vessel and alarm system is also included. The operator used a service company to engineer, procure, install, and commission two QPFs. From a process perspective, the primary challenges encountered included flow assurance related to the presence of a variety of oils and wax with high wax appearance temperature (WAT), limited existing infrastructure in the very remote location, and compliance with the India DGMS standards. After all of the equipment/skids arrived on location, the operator requested the installation of the QPFs within a short period of time. A team consisting of local contractors and global personnel from various disciplines was assembled to meet the challenge. This team included personnel from project management, mechanical and piping, electrical and instrumentation, and construction and commissioning. The installation and commissioning of the first QPF was completed in 45 days. After applying lessons learned from the first installation, the second QPF installation was completed in only 25 days. The commissioning of the facilities in such a short time period was the result of collaborative work from both the operator and the service company. Two modular, skid-mounted, plug-and-play QPFs with the capacity for quick relocation and commissioning within multiple fields were installed in very remote locations in India. This paper discusses challenges encountered and addressed during the operation using an economic, flexible, and reliable QPF model. Lessons learned during the first operation enabled a much faster completion of the second QPF, thus exceeding operator expectations.

Water injection is one of the methods for maximizing oil production and improving oil recovery by way of maintaining reservoir pressure. It entails injection of water in sufficient quantities with acceptable quality into the appropriate zones of the reservoir in a cost efficient manner. Treated water is transmitted from treatment to well generally through carbon steel pipelines; as there are flexible pipelines, internally coated pipelines being used for water injection also. And this paper is solely for carbon steel pipelines. The corrosion of these water injection pipelines is a major issue for the Oil & Gas industry with a view to preserve the reservoir permeability and integrity of the pipelines. A few case studies pertaining to failure of API 5L carbon steel subsea water injection pipelines with their root cause analysis are presented in this paper. In order to identify the cause and mechanism of failure, detailed laboratory and analytical investigations were carried out with a view to characterize the material property as well as to evaluate the corrosivity of operating environment. Studies like visual inspection, non destructive testing, corrosion product analysis, elemental compositional analysis, metallographic investigations, inclusion content test, hardness testing, tensile strength studies, impact test, stereomicrscopy, scanning electron microscopic (SEM) coupled with energy dispersive spectroscopy (EDS) studies, have been carried out. Process parameters, operating & maintenance practices, chemical treatment program with quality parameters etc. have also been critically examined. Pipeline material was found to conform to the specification API 5L. The analysis showed that the most probable cause of the failure of the pipeline was under-deposit/grooving corrosion, which started with oxygen and Microbiologically Influenced Corrosion due to Sulphate Reducing Bacteria and was subsequently supported by very low flow velocities in those pipelines. The stagnant water and the formation of thick deposit consisting of corrosion product, sludge or suspended solids and biomass as a result of proliferation of bacterial colonies were the conditions for attack to set off. Galvanic corrosion further accelerated the metal loss process as grooving/channeling resulting into failure at 6 O'clock position. Presence of large number of inclusions in some of pipeline materials was an additional cause of accelerated corrosion process. On the basis of root cause failure analysis, the major integrity threats to the water injection pipelines resulting from process control were identified. Accordingly, preventive and remedial measures essential for preserving integrity of water injection pipelines have been suggested. Implementation of good operating and maintenance practices, robust quality control measures, continuous monitoring of corrosion trends, prompt corrective actions are the key requisites to abate failures due corrosion.

Single Point Gas Lift (SPGL) is preferred in subsea wells due to its certain advantages over conventional completion with unloading valves in meeting the aim for no intervention, pressure barrier requirements etc. Current paper presents a flow assurance study of an SPGL system in a deepwater field in India. The development strategy envisages clustered subsea wells with common flowlines connected to an FPSO about 12 km away. Requirement of gas lift is envisaged from mid-life due to expected depletion in reservoir pressures and increase in water cut. Subsea gas lift in deepwater environment typically requires higher injection pressure to lift from desired injection depth. The gas lift, flowline and riser system is expected to operate over a wide range of conditions in terms of fluid composition, pressure and flow rates. Optimum design and operation of an SPGL system under such conditions is a challenge. Integrated dynamic modelling from down hole to host facility at the pre-FEED stage can provide valuable inputs for system design and operability. The impact of various gas lift parameters like orifice size, setting depth, kick off pressure and operating injection pressure on the system has been studied. The field is having waxy crude with high pour point of 36°C with gelation propensity during long shut downs. The paper also brings out the operability windows during start up, turndown, shutdown, restart etc. and their impact on topside design. Transient modelling has been used to invetigate threats to system integrity due to high velocities of fluid through orifice, low temperature limits due to JT cooling, pressure surges into the production line resulting in large slugs arriving at FPSO. Slugging in riser may lead to process shut downs due to the pressure and rate variations resulting in loss of production. Design and optimization of the SPGL system is also aimed at increasing total production by avoiding process shut downs due to well instability and pipeline slugging.

This paper proposes solutions to safety issues by means of modifications to equipment engineering designs. Additionally, instilling a design-for-safety (DFS) philosophy helps further promote a safety culture. DFS is a key component of engineering. It is essential to anticipate and visualize potential safety hazards in a design at a nascent stage and solicit feedback from customers and field personnel. In most cases, making minor design changes early can greatly reduce the probability of possible hazards. Additional unexpected benefits of this process can include reductions in injuries, costs, and downtime. One example of this DFS concept is the addition of a hurdle block to avoid finger pinching when sliding pipe in pipe on a modular structure. Another example is the conceptualized design of a "mistake proof" manifold stack, which can only be stacked in ascending order of heavy to light weight. This helps avert the risk of heavy objects falling and reduces the need to lift heavyweight objects. Without using DFS, equipment might be manufactured that could present potential hazards later. However, DFS helps identify potential hazards during the design stages by performing failure mode and effects analysis (FMEA). Critical thinking is crucial. Safety features, such as additional gussets, pins, blocks, etc., that do not serve any core functionality are added to mitigate these potential fallacies and hazards. This paper provides examples to engineering solutions wherein a combination of DFS techniques and field feedback helped reduce potential hazards. Using this approach should help instill a safety culture. Enhancing safety has always been a challenge in engineering applications, and the oil and gas industry is no exception. A collaborative effort in which design changes are requested from field operations not only adds value to the design from a safety perspective but also ensures customer input is considered.

This paper relates severe lost circulation problems often encountered when the well is drilled overbalanced through high-permeability, fractured, or easily fractured formations. As numbers of LCM pills, neat cement plugs were placed in damaging and non-damaging reservoirs, resultant failed to provide an adequate solution. Recently, severe mud loss problems were encountered during drilling in Mumbai Region from depleted reservoirs, unconsolidated, highly permeable, fractured and fragile limestone formations, both from nonproducing and producing reservoirs (L-III, L-II, L-I, H1A, H3B, etc.). The losses range from 100 BPH to total loss. Attempts are made to stop the losses with the placement of advanced lost circulation treatments. To mitigate these types of losses, an innovative technique developed with a temperature-activated Rapid Setting Fluid (RSF) Pill from indigenously available chemicals and used as an alternative to LCM / cement plugs for severe loss control problems in Mumbai Offshore. The RSF system has proven successful for curing severe dynamic and static losses by pumping treatments through the drill string bottom hole assembly (BHA) (no trip out required) and taking advantage of its highly controllable fast setting properties. The RSF pill is a stoichiometric mixture of magnesium compound, forming hard and a series of high mol. wt. magnesium inorganic poly-hydrates, displaying characteristics of conventional cement slurry in pumpability, but very different chemically. As the RSF Pill enters the lost zone, it sets rapidly (a rapid transition from liquid to solid) and builds sufficient compressive strength within 5-6 hrs. The reaction causing solidification is wholly a function of time and temperature and unaffected by hydrostatic pressure. The pill is non-damaging as it is non-invasive, sets at the lost zone mouth and 90-100 % soluble in 15 % Hydrochloric acid. The pill can be successfully used up to 140 °C BHST. The field trial has been carried out successfully in two wells of Mumbai Offshore: N_12#3Z (Mumbai High L-III reservoir) in partial loss conditions and HG#6H (Miocene Bandra Limestone formation) with total losses. It has also established that the new Loss Control Solution, RSF Pill can be placed successfully in all types of lost zones (like L-III, L-II, L-I, H1A, H3B) to mitigate the mud losses. The paper also details the specific chemical and mechanical characteristics and field performance of the RSF pill. It concludes that the combination of unique fluid properties and best practices in fluid placement procedures plays a vital role in the successful implementation and development in the treatment of loss circulation in limestone formations. This technique is unique, easy, very effective and provides cost benefits.

The Keshen reservoir is a naturally fractured, deep, tight gas sandstone reservoir under high-tectonic stress. Stimulation is critical to the successful development of the Keshen gas field. However, due to the heterogeneity of the natural fracture system in the reservoir, there is large variation in natural productivity from production wells, which mandates different types of stimulation operations from simple acidizing to massive hydraulic fracturing. Hence, to improve the efficiency of reservoir stimulation and overall performance of the reservoir development, reliably evaluating the natural productivity from production wells and optimizing well stimulation strategy (by selecting appropriate stimulation operations) are required. To this end, single well production history matches were conducted to calculate the natural fracture (NF) permeabilities for 12 acidizing wells with known matrix petrophysical properties. It was found out that the NF permeability is clearly correlated to the intersection angle ((, angle between maximum horizontal stress and NF strike) and Young's modulus (E), based on detailed natural fracture interpretation and geomechanics analysis. By using a correlation with the intersection angle and Young's modulus, the NF permeabilities for seven hydraulic fractured wells with large size treatment were obtained and the natural productivity for each well was predicted. By comparing predicted natural productivity with actual post-stimulation productivity, the productivity enhancement by hydraulic fracturing treatment was determined. The comparison showed that the productivity improvements by hydraulic fracturing treatment were very limited and unnecessary for the wells with high natural productivity, while improvements were substantial for others. Subsequently, the well stimulation selection criterion was formulated, which classified wells into three categories based on the natural productivity, and specified stimulation method was recommended for each well category, respectively. This paper shows an example: the natural productivity of a newly drilled well was predicted, and massive hydraulic fracturing was selected based on the stimulation treatment selected criterion. The well was successfully stimulated with absolute open flow (AOF) of 3.6 MMm3/d, which doubled the natural productivity. The workflow used to estimate the natural productivity of the tectonically active Keshen reservoir and to establish the well stimulation selection criterion, and their application and validation, which are rarely published previously, are presented in this paper.

This paper aims to cover importance of Stakeholder Management in business continuity and its linkage with different business segments. Stakeholder Management looks at the relationships between an organization and others in its internal and external environment. Stakeholder could be a person or a group that can affect or be affected by business activities. Stakeholders can come from inside or outside of the business. Examples include customers, employees, stockholders, suppliers, non-profit groups, government, and the local community, among many others. Effective stakeholder management is very crucial to a company’s success. The core idea is that organizations that manage their stakeholder relationships effectively will survive longer and perform better than those organizations that don’t. All community relations issues must be fully addressed prior to and during the development of facilities via participation and consultative mechanisms promoting active communication involving all key stakeholders. Ensuring awareness of cultural differences, respecting diversity and adjusting our ways of working in different situations as well as recognizing and responding to government and community related expectations and concerns about our activities are crucial to companys business. Leading a structured stakeholder dialog and managing the stakeholder relationship is connected with all operations and starts from local communities, notables, political influential to district, division, provincial and federal authorities. In order to succeed and be sustainable over time, companies must keep the interests of customers, suppliers, employees, communities and shareholders aligned and going in the same direction. However, in some countries like Pakistan where industry faces difficult social and political environments where governments may lack the capacity, infrastructure or enforcement of legislation and regulatory frameworks, Stakeholder Management could be very challenging. Through this paper a model shall be proposed based on best practices of leading Oil & Gas companies in Pakistan, as how different topics such as Sustainable Social development, Community Engagement, Managing Social Risks and their impacts, Human Rights, Local Content & Related Security could be aligned to create the possible much value for Stakeholders and ensuring social license to operate.

Using carbon dioxide for enhance oil recovery (EOR) has attracted a great deal of attention as the world grapples with the twin challenges of improving oil recovery from mature oil fields and reducing emissions of greenhouse gases. CO2 is considered to be a favorable EOR agent as it can result in a miscible flood process while being less expensive compared to the other similar choices (solvents). Although very fascinating when expressed in terms of numbers and benefits, the life-saver CO2 flood/sequestration projects may turn into a potential risk to the environment when not operated and monitored appropriately. The fact that many oil and gas formations have hold hydrocarbons for millions of years prior to hydrocarbon production provides the fundamental support for possibility of storing CO2 in similar formations however it may induce the risky conception of over-trusting these formations to securely store CO2. Hence, monitoring the CO2 injection process appears to be a necessity in these projects, not only because it helps to improve the efficiency of the process, but also to reduce the risk of CO2 leaking out of the storage zone. In this paper, we investigate the reliability of 4D seismic interpretations as a potential monitoring tool by comparing its results to that of numerical simulation in a CO2 injection project at Cranfield, Mississippi. The numerical simulation model is tuned using historic pressure trends, oil and gas production rates, and current CO2 production data and its validity is confirmed before using it for predictive simulations. Two seismic surveys were performed before and after CO2 injection has started in Cranfield. The first seismic survey was acquired in 2007 (baseline) and the repeat survey was acquired in 2010, when approximately 2.2 million metric tonnes of CO2 has been injected into the reservoir. Seismic surveys were performed in the northeastern part of the reservoir. The overlapping region covers an area of approximately 6 km × 6 km. Using seismic surveys as monitoring methods has the advantage of covering a large area where it can provide information about the CO2 saturation/distribution at locations in which no monitoring well exist. Three different interpretations of the seismic data are discussed in this project. The first interpretation is achieved by generating the time-lapse seismic amplitude difference maps (comparison of the post-injection and pre-injection surveys). The time-lapse amplitude versus angle (AVA) data is then further analyzed by applying a pursuit pre-stack inversion to obtain elastic properties of the reservoir. The last interpretation that is discussed in this papers is achieved by linking the elastic properties of the media to the variations of CO2 saturation, lithology, and cement content using rock-physics models. The distribution maps achieved from each of the above mentioned interpretations are then compared to the numerical simulation results. According to the results, although sensible match between 4D seismic interpretation and simulation results is observed in areas of higher CO2 saturation, areas with lower CO2 saturation show a less clear match. In fact, our compassion of CO2 saturation distribution with interpreted 4D seismic data is not as successful and there are clear discrepancies. We had access to three independent interpretation of the 4D seismic data and discrepancies are observed both in locations with high and low CO2 saturation in all interpretations. It is clear that 4D seismic interpretations have some issues as they are incapable of interpreting CO2 saturation around the injection wells. It seems that collected 4D seismic data in Cranfield suffer from several challenges, impacting the reliability of the interpretations. These challenges include the depth of the formation (higher pressure makes the CO2 density to be higher reducing its contrast with oil and water), thickness of formation (net sands are less than 20 m), presence of methane in the reservoir (this can hinder interpreting the added CO2), and low gas saturations (relative permeability curves also show that gas saturation would barely go over 30-40% in most part of the reservoir).

Abstract This paper discusses Synthetic Coal Cycle Technology™ (synCCT™), a novel, patent pending, energy conversion and storage technology that uses carbon dioxide (CO2) to make grid-scale renewable energy dispatchable. synCCT uses renewable energy to dissociate CO2 into carbon, a renewable fuel named Synthetic Coal™ or synC™, and oxygen. synC is oxidized to generate electricity and heat on demand, producing CO2, which is captured and reused in the process. Both synC and CO2 are feasibly and economically stored for long periods and/or transported long distances by conventional technologies. The synCCT process is carbon neutral and sustainable. In addition, synCCT has a number of advantages over competitive technologies, including:No greenhouse gas (GHG) emissionsSimplified integration of grid-scale renewable electricityVirtual transmission of renewable electricity without wiresSimplicityNo pollution or waste productsMinimal water useRelative safetyLow toxicityMinimal infrastructure development requiredPotential use and repurposing of existing infrastructure This paper discusses the rationale for synCCT, how it works and how it compares with competitive technologies for producing renewable fuels from CO2. Introduction The embodiments of Synthetic Coal Cycle Technology™ (synCCT™) discussed in this paper simultaneously address two major issues for the production of electricity: carbon dioxide (CO2) emissions and the limited availability of solar and wind energy to reduce these emissions (Zietlow 2014). Although renewable energy sources, such as wind and solar power, reduce CO2 emissions by replacing fossil fuels, this reduction is limited by their availability. Because most renewable energy sources are either intermittent, geographically fixed or both, they are often not available when and where needed. Although intermittency can be mitigated to some extent by using peaking generation or conventional energy storage, both have significant limitations. Peaking generation emits CO2 and most commercially available energy storage only works over short time frames. Both require capital investment beyond that for renewable energy generation, often including new, expensive electrical transmission lines to transport the electricity they provide. synCCT converts renewable energy to a fuel, Synthetic Coal™ (synC™), that stores renewable energy indefinitely and can be transported significant distances by conventional transportation, thereby, solving the problems of intermittency and fixed location without the need for new electrical transmission lines. Although synCCT requires additional capital investment beyond that for renewable energy generation, the added value of greater location and time flexibility, and the avoided cost of new electrical transmission offsets its cost relative to peaking generation and conventional energy storage.

Abstract In this paper we present a study on the feasibility of utilizing the mature Monterey oilfields of offshore California for sequestering carbon dioxide while potentially enhancing crude oil recovery from the tight matrix. An important characteristic of these fields is that, because of natural fractures, well productivities have been high and as a result, a significant amount of reservoir voidage has been generated in each field by production of more than 780 million barrels of oil and more than a TCF of natural gas during the last three decades. These productions translate into a computed voidage of about a billion barrels allowing storage of more than 90 Million tons of CO2. This is roughly equivalent to storing 50 years of CO2 from a 400 MW Power plant. Another important observation discussed in the paper is the cap rock sealing nature of these fields allowing preservation of the oil and initial pressure as evidenced from the analyses of the initial GOR data. Furthermore many of these fields will be at the verge of abandonment during the next two decades unless steps are taken to enhance recovery by extracting oil from the tight matrix. CO2 extraction from tight rocks is a technically feasible process and our analysis indicate that CO2 storage can indeed prolong the life of many of these fields and enhance matrix oil recovery. An important infrastructure requirement for CO2 transportation into these offshore fields is the cost of building offshore pipelines. Availability of existing multiple pipelines connecting the fields to their corresponding onshore treatment facilities solves this transportation of CO2 to the offshore fields. Finally, these fields are under active water influx, where aquifers may provide additional CO2 storage possibilities.

Stress (or pressure) dependence of coal permeability is a commonly observed and generally accepted dynamic behaviour that is often ignored from production performance forecasting. Reasons for this omission typically include (a) the difficulties in reliably characterizing stress dependent effects from a limited number of pressure buildup tests, and (b) large uncertainties in our understanding of both the porosity and compressibility of coals. This paper demonstrates a new analytical workflow, and proposes a new set of equations that overcomes some of those limitations through acknowledging and accounting for stress dependent permeability (SDP) behaviour with radius - during testing and production - by translating expected permeability changes with pressure, to productivity changes with pressure gradient. This paper utilizes a slightly modified form of Palmer-Mansoori (P&M) model in a workflow that includesEstimation of coal cleat volume compressibility using permeability-depth trendsCharacterization of mechanical skins from interpreted apparent skinsCalculation of "stress dependent pseudo pressure" (SDPP) – converting permeability changes with pressure to productivity changes with pressure gradient – enabling the use of well productivities over time as part of a SDP characterization processThe matching through regression of relative changes in well productivity indices in groups of wells - utilizing the SDPP approach – with a single stress dependent controlling parameter, in a way that is suited to extrapolating away from well control. The paper provides the theoretical support for this approach via derivations from published models, and then outlines the methodology – sharing the results of a field example – demonstrating the relative ease with which the analytical process can be applied. Further, it highlights pitfalls of using well productivities as a direct proxy for permeability changes, or even utilizing coarse grid numerical simulation in the matching process. Finally, it also discusses further applications and limitations of its application. This paper addresses existing knowledge gaps in the CSG industry by providing a simple, yet efficient, workflow for characterizing and incorporating stress-dependence of permeability in CSG Reservoir Engineering. This is achieved through the application of new analytical equations to characterize stress dependent pseudo pressure, enabling the direct use of well productivity changes, and can be used standalone, or as a means to accelerate a numerical history matching workflow.

This paper describes evolving energy resource regulation within Queensland, with emphasis on optimising the State's petroleum resources. Key elements of a proposed resource tenures management framework and reforms to geoscientific information reporting are discussed in the context of petroleum industry trends. A discussion on the role of the regulator provides context to these reforms. Queensland is a world class resources province within a globally competitive market. The sector produces significant quantities of bauxite, coking coal, lead, silver, zinc and coal seam gas (CSG) and is vital to sustaining economic development and growing jobs within the State. Queensland's petroleum tenures management framework continues to evolve, to meet industry and stakeholder needs. In September 2015, the Minister for Natural Resources and Mines released the government's Innovative resources tenures framework – Policy position paper. The paper identifies aspects of the current tenures framework which do not work effectively within a modern and globalised resources sector. An innovative and contemporary framework – designed to strike the right balance between resource development, environmental sustainability and investment attraction – is proposed. Geoscientific data reported by petroleum tenure holders enhances knowledge of the State's resources and valuably informs pre-competitive resource assessment and exploration and development opportunities. Ongoing Department of Natural Resources and Mines (DNRM) reform aims to improve delivery of quality geoscience data to the sector while reducing regulatory reporting burden. Finally, the paper highlights typical resource activity challenges and how these can be met through effective dialog between the tenure holder and DNRM. As in other areas of venture management, such a dialog can be used to address issues before they become critical.

Modern hydraulic fracture treatments are specifically designed to unlock reserves from particular rock types, especially in unconventional reservoirs. Progressive improvements in fracture design can be critically informed by post stimulation pressure analysis, yet this process is often overlooked. This paper documents the evolution of fracture designs by successively incorporating post-stimulation pressure analyses after major design changes that ultimately led to the design-optimization of fracture treatments in low permeability coals. The coals under context are the Walloons coal measures in Jurassic to Cretaceous aged rocks in the Surat Basin of southeast Queensland, Australia. Significant challenges are faced in stimulating the Walloons coal measures due to their thin-bedded nature, that range from 0.2 to 3.0 m [0.66 to 9.8 ft] in thickness and, which are also inter-bedded with low permeability siltstones, minor sandstones and carbonaceous shales. Net coal thickness is 20 to 40 m [98.43 to 131.23 ft] in a gross sequence of 300 to 400 m [948.3 to 1,312.3 f] thickness. Reservoir complexity is further impacted by lateral continuity variations of coals, which generally have a high Poisson’s ratio (>0.32). In particular where coal reservoirs display low permeability, understanding and implementing reservoir beneficial fracture treatments becomes pivotal to successful well performance. Modification of fracture designs during the fracture campaign included changing key parameters such as fluid types, pump rates, proppant loading and gel concentration. Both, the treatment and the calculated bottom-hole pressures, were evaluated using 3D fracture models, supplemented by an array of diagnostics such as surface tilt-meters, diagnostic fracture injection tests, micro-seismic monitoring and tracer logs as well as log derived stress models. The results of these diagnostics helped shape the design changes implemented throughout the campaign and has influenced designs for future trials also. Ultimately, it was observed that the treatments that were pumped using low gel loadings in conjunction with high proppant concentrations, and at relatively lower rates, resulted in better well performance. This paper presents the design and treatment evaluation process and also provides an insight into the progression of fracture design and subsequent treatments which were successful in overcoming reservoir complexities. The outlined approach can be used to refine hydraulic fracture treatment designs in similar complex reservoirs in Queensland, with worldwide applicability.

The Bone Springs play of South East New Mexico USA is currently in full development. The play contains three pay sections, with all, two or sometimes just one pay section providing economic hydrocarbons for Operators to develop and exploit. This paper will discuss the evolution of how the play was developed by abandoning vertical wellbores, and then using horizontal wells with multi-stage fracture treatments. The paper will focus on how each hurdle was overcome to discover economically beneficial technology including: lateral azimuth; lateral length; frac fluid and proppant selection; fracture design and evaluation as well as production results for each hurdle. Further discussions will emphasize the selection of lateral landing depth and the impact of depth on propping each fracture, the evolution from perf-and-plug to selective isolation with usage of sliding sleeve technology as well as the final state-of-the art on well design for the play. All of these facets are proven to demonstrate an improved production and cash flow to generate an optimized well plan. Key learnings will be in the area of logic, the workflow to determine key anchor points from data and understanding trade-offs for less expensive yet not as rewarding technologies and practices.

The measurement of gas content of coals has been dominated by the standard methods of core desorption described by ASTM D7569 and AS3980 (1999). In this paper the limitations of these procedures are discussed with particular reference to the partial gas pressure the gas content is being referred to. Because the gas content is always quoted as an absolute value measured to an undefined gas partial pressure as opposed to a value at atmospheric pressure it brings into question the nature of the isotherm model being used at pressures below atmospheric. The generally accepted Langmuir model is found to be lacking at these lower pressures and alternative options are considered. The current practise of measuring isotherms is also questioned, particularly with respect to mixed gas types where the extended Langmuir or IAS models are found wanting. To overcome these deficiencies the process of measuring gas contents to known partial pressures of seam gas is used. So too is the process of measuring native isotherms on initial desorption of core. This is extended to the measurement of laboratory isotherms at reduced pressures. The results of isotherm testing indicate that the native isotherms are generally not the same as isotherms derived from laboratory testing though they are more similar where the seam gas is of a single composition. By undertaking isotherm tests to lowered pressures we can see that there are shortcomings in the Langmuir equation and that gas storage at lowered pressures may vary substantially from this model. The measurement of gas content by conventional desorption needs to be measured to a known partial pressure and this needs in turn to be related to the isotherm. This paper uses some basic science to produce better solutions to gas content analysis. Along with these developments comes the analysis of desorption of a sample and how this relates to the diffusion coefficient and core fracturing. This leads in turn to an improved process to determine the lost gas on core retrieval for coals and shales.

Acceptable data quality for formation evaluation forms the foundation for understanding the petrophysical & reservoir properties, coal quality and properties and pay zones identification. The petrophysical logs are used in both subsurface modelling and to optimise the well completion strategy, ensuring effective coal dewatering and desorption for gas production. At the moment, the industry common practice for data acquisition is to use open-hole wireline logging tools, which were developed primarily for the oil and gas industry. These tools are designed for higher pressure and temperature specifications compared to the reservoir conditions normally seen in CSG operations. This results in heavier tools, bigger logging trucks and increased manpower requirements than seen in mining logging operations. Arrow's CBM development projects in Queensland, Australia, are designed with a large volume of wells (more than ~1000 wells) that will need to be drilled and evaluated over the next ten years. At present, the cost of logging (direct wireline contractors and associated rig time cost) is forcing Arrow to choose between early data coverage (eroding project economics value) versus restricted logging (increasing project risk). In order to resolve this issue, Arrow has embarked on a series of technology trials to investigate various cost effective formation evaluation solutions, while still ensuring data quality and operational safety. This paper will present the results of a comparison (logoff) of state-of-the-art mining logging technology and conventional oil and gas logging technology. Also, the paper will focus on the mining-style logging technology data quality, equipment footprint, tool handling, calibration procedures, limitations and general operational efficiency.

An operator working in the STACK and Mississippi Lime plays of the Mid-Continent region in the United States is developing its acreage with the use of open hole multistage (OHMS) completion systems. This paper will detail new technologies and advancements that are providing enhanced economic benefits and enabling the operator to unlock the full potential of the targeted formations. The operator holds one of the largest acreage positions in the Mid-Continent region and in 2014 had operated or participated in approximately 170 horizontal wells. This operator approached its development with the goal of reducing completion costs; bringing completion costs in line with estimated completion costs; reducing health, safety and environment (HSE) exposure, while reducing cycle time; and preserving estimated ultimate recovery (EUR) of its assets. Some of the new technologies and advancements to achieve these goals include: changing core completion methods, radioactive tracers, dissolvable balls, high-rate water stimulation, extended reach laterals, microseismic analysis, water-soluble tracers, oil-soluble tracers, stage spacing and statistical analyses. These new technologies and advancements adopted by implementing OHMS completion systems provided the operator with significant cost savings when compared to previous wells completed in the region using cemented liner plug-and-perf techniques. Lessons learned from each well were applied to future wells and the operator realized further cost savings as it continued development of the region using OHMS completion systems. These cost reductions were achieved while preserving the EUR of the assets, increasing the economic viability of the operations. The technologies, methods and procedures will be presented in this paper to help paint a picture of how this particular operator is leading the way in reducing completion costs and increasing reserves. The details provided will show how OHMS technology is a cost-effective option for operators drilling and completing horizontal wells in the Mid-Continent region of the United States and provide strategies that can be applied in other formations around the world.

The combination of horizontal drilling, multistage completion and hydraulic fracturing has been the key factor for the successful development of the Bakken play. This dominant status reflects in two aspects: the enhancement of well production, making stripper well even dry well valuable for industrial development, and the effect of long-term flow conductivity on the ‘sustained yield’ of well. This paper quantitatively analyzed the stimulation design factors and their interactions contributing to incremental and long-term productivity of horizontal wells in Bakken respectively for different geologic environment. Data from more than 1000 wells located in the Bakken Central Basin area containing production and stimulation design have been collected from the Premium Services of North Dakota Industrial Commission (NDIC) website and the FracFocus.org. Wells were grouped and analyzed by similar water cut based on cumulative production for the normalization of variation in geologic heterogeneity. Response surface methodology (RSM) was applied as the methods of quantitative analysis to determine the contributing factors and their interactions. In this study, 2-month and 12-month cumulative oil production per perforated length were used as the indicators of incremental productivity and long-term productivity respectively. The data are divided into three reservoir-homogeneous groups according to different water cut range and a separate slickwater fracturing group. The effects of stimulation design factors and their interactions on the incremental productivity and long-term productivity were investigated. Results indicates that among all the factors, perforated length, proppant/perf length, water/ perf length, percentage of ceramic are the most contributing factors of stimulation design to incremental and long-term productivity. Different group are influenced by different combination of contributing factors. Most groups share the same significant interaction between perforated length and water/ perf length, as perforated length increases and water/ perf length decreases meawhile, the cumulative oil production per perforated pength climbs rapidly, with the amount of other design factors fixed. Previous similar analysis focused on 30, 60 and 90-day cumulative production with smaller data volume to generate well performance metrics for the lack of enough wells. This paper utilized the larger data set with longer production time span and analyzed the stimulation design factors contributing to incremental and long-term productivity of horizontal wells in Bakken respectively. These results are more valuable for optimization of stimulation design in the Bakken play and similar reservoirs faced with dynamic and changing oil market.

The Eagle Ford Shale in the southern part of Texas is a carbonate-rich, oil-producing, organic shale. Typically, wells are drilled horizontally through the target section of the Eagle Ford shale formation. A long string production casing is then run and cemented in place. A plug and perforate completion helps enable hydraulic fracturing of multiple target intervals along the lateral section of the wellbore. Before fracturing the wellbore, pressure testing of the casing string to the maximum fracturing pressure has become an industry best practice. Then, a flow path is created at the toe of the wellbore using tubing-conveyed perforating (TCP) guns run into the wellbore on coiled tubing (CT). With the constant drive to improve efficiency and lower completion costs, pressure-activated toe sleeves (PATS) have rapidly replaced the TCP CT run to create the initial fluid flow path. The PATS is run as part of the completion casing and cemented in place. Internal casing pressure is then applied to open the PATS and create the flow path. However, to accomplish a casing pressure test, the first generation PATS design must have the activation pressure set higher than the testing pressure. The casing test pressure must then be exceeded to open the PATS which is not ideal operationally for a variety of reasons. This paper reviews a case study where a new, second generation PATS was used in an Eagle Ford shale well to allow a true casing pressure test and provide the initial flow path. The paper discusses the subject well, design, and operation of second generation PATS technology, and presents the results of the application. The positive economic impacts are also reviewed. The paper draws conclusions based on the results from the subject well, operation of the new PATS tool, and the economic impact experienced.

The Spring Gully coal seam gas (CSG) field, operated by Origin Energy on behalf of Australia Pacific LNG, is located in the southern region of the Bowen Basin. Commercial production commenced in 2005 from the Late Permian Bandana coal seams. This paper describes the reservoir characterisation methodology employed to history match geologically unique regions of the Spring Gully field and to understand production mechanisms across the field. In addition, the paper presents a detailed discussion on how learnings from the developed region of the field has been applied to characterise the future development regions of the field for forecasting. The Spring Gully CSG field exhibits a large degree of localized heterogeneity and extensive regional geological variability. Strong gas productivity and rapid water gas ratio decline have been observed in the north-eastern region of the field. While in the western portion of the field there exists moderate gas productivity and minimal water decline. A comprehensive, multi-disciplinary evaluation of the Spring Gully CSG field reservoir and production characteristics was performed in 2014. A reservoir simulation model has been constructed based on a number of geological and reservoir characterisation studies, combined with reservoir inputs and production analysis. The integrated subsurface model forms the basis to understand Spring Gully CSG field production mechanisms and ultimately to perform production forecasts for reserve and resource estimates, for ongoing reservoir management needs and appropriately size gas and water treatment facilities. A novel approach of constructing the permeability and porosity distribution in the reservoir model was implemented. Historical well peak water and gas rate, rig testing water rate and welltest-derived permeability were used to construct the permeability distribution in the model. The permeability distribution was transformed to porosity distribution. The faulting and compartmentalisation were introduced in the north-eastern region of Spring Gully reservoir model during the history match stage to match the rapid decline of reservoir pressure. The learnings obtained from studying well production mechanisms and model history matching were subsequently applied to the undeveloped regions of the field. Extensive validation and quality control of forecast methodology, forecast parameters assumptions and life-of-field production forecasting were performed.

This paper will summarize an approach for developing and rolling out high-impact safety leadership training programs to managers and employees of onshore and offshore upstream oil assets. The main objective of the paper is to illustrate how to integrate the Accelerative Learning (AL) methodology in the design of safety leadership trainings in order to enable people throughout the organization to understand and act upon HSE priorities for their company with the ultimate goal to improve safety performance, achieve cost savings, reduce risk and raise employee safety awareness and motivation. The approach to design and delivery of safety leadership trainings uses the AL Methodology, which is considered to be one of the state-of-the-art learning approaches that are in use today, and which is based on the latest research on reconciliation between the brain physiology and the learning process. The method is based on addressing the Auditory (A), Visionary (V) and Kinaesthetic (K) learning modalities through the AL Cycle. The incorporation of this methodology in the safety training programs design and delivery effectively seeks to de-mechanize and re-humanize the learning process and make it mind and body experience, achieving maximum level of information retention and enhancing a transition from safety management approach to safety leadership mindset. Incorporation of both active (practice by doing, discussion groups, immediate use of learning) and passive (lecture, reading, audio visual and demonstration) methods of engagement under the AL philosophy into the design and delivery of safety leadership programs helps to achieve up to 95% retention of information, leading to higher competency outcomes and immediate linkage of the concepts back to everyday realities in the field. The following results were achieved with the application of this concept to safety leadership development of personnel in onshore and offshore upstream assets: ▪Developing ability to understand motivational and behavioural profiles of personnel and apply relevant tools to influence, engage and create positive change in the safety performance of organizations (achieving an up to 70% improvement);▪Developing ability to demonstrate visible and felt safety leadership from front-line level-personnel up to the management teams;▪Enhancing personal leadership capability to build safety into newly established teams, and prepare them for new responsibilities to pave the road for operational success.

Eco-friendly water deoiling systems for effective water treatment presents a significant operational and environmental challenge during exploration and development well testing and clean-up operations in offshore environments. As an alternative to traditional storage, transport, and disposal onshore, some offshore operations have attempted to use mobile water treatment systems to reduce the oil-in-water content from the produced water to an acceptable level, before safely discharging overboard in accordance with the local regulatory permitted environmental limits. When this can be routinely and effectively performed, offshore water treatment units may provide an efficient and cost effective alternative to conventional approaches of onshore treatment and disposal of aqueous effluents and waste streams. This paper outlines the operational envelopes and limitations of current commercially available water deoiling systems, and introduces a relatively recently developed mobile light water treatment unit. This new generation light water treatment unit consists of a horizontal vessel containing five coalescing beds evenly distributed along the vessel length and inlet centrifuge for solids removal. The vessel combines both coalescing and gravity separation techniques that is capable of reducing oil-in-water (OIW) concentration to less than 20 ppm. The primary coalescing material is a reusable petroleum absorbent polymer that can be regenerated through centrifugation onshore. Therefore, unlike more traditional water filtration and deoiling systems, it generates no additional waste or by-products. The field applications highlighted in this paper demonstrate the results and lessons learned from successful deployments of this new generation light water treatment unit in firstly offshore well test operations and subsequently the inspection and dewatering of subsea pipelines in environmentally sensitive areas.

In June 2009, a PSA was signed for Absheron field by Total Exploration and Production (TEP) Absheron BV, as operator, and SOA (SOCAR Oil Affiliate). Soon after GDF SUEZ E&P Absheron B.V. joined the venture and shared its commitment to drill an exploration well, ABX-2, within the 3 years of the first exploration period. ABX-2 was spudded in January 2011 with the Maersk Heydar Aliyev semisubmersible drilling rig. In September 2011, a major gas condensate discovery was announced. In June 2012, the JV declared the commerciality of the newly discovered Absheron field. ABX-2 well was suspended in September 2012. In 2015, Absheron field development studies are progressing to pre-FEED stage, based on well data from ABX-2. The South Caspian basin is known to be a prolific oil and gas region but yet a challenging environment for drilling. Absheron structure which lies in 500m water depth with exploration objectives from 5500m to 7000m is no exception. This paper illustrates the challenges that TEP Absheron BV anticipated and faced during the preparation and the execution of ABX-2 drilling program. It elaborates on particular aspects of the mobilization of drilling operations in Azerbaijan including logistical means, rig modifications, as well as the multiple drilling technologies and strategies that were developed at the planning stage to the actual drilling operations illustrating how the drilling solutions permitted management of unexpected situations and to complete exploration objectives. The paper also demonstrates the value of factoring the potential appraisal strategy (well testing, geological sidetrack) into an exploration well design in order to maximize the appraisal value gathered from the exploration well allowing acceleration of the field development sequence.

Since the disastrous events of Eastern Air Lines Flight 401 in 1972, KLM 408/Pan AM 736 in 1977 and British Midlands 92 in 1989, the aviation community have worked together to develop, deploy and mandate crew resource management (CRM) training for aircrews with recognisable benefits being shown in terms of operational safety, crew performance and cost savings. Unfortunately, it took a number of major incidents in the Oil and Gas sector (Piper Alpha in 1988, Montara in 2009 and Macondo in 2010) to raise the priority of human factors and crew resource management training despite papers being written to this effect. From 2012 onwards, the International Association of Oil and Gas Producers (IOGP) published three reports in the form of Reports 460, 501 and 502. At this point, there was clarity of what Well Operations CRM (WOCRM) should consist of and how it should be deployed. This report covers the delivery of WOCRM training and individual coaching to the supervisors from one prime operator who had contracted four drilling rigs operating under three drilling companies in a Middle East location. Over an 8-month period, 121 supervisors from a multitude of nationalities, cultures and experiences were trained and coached on the skills required for effective WOCRM. The training used Report 502 as the basis for the course content but went futher and one-to-one coaching was also provided on the rigs to consolidate classroom learning. This paper will identify the challenges faced in deploying such training, given that much of the research into WOCRM has been carried out in single cultural environments e.g. the North Sea or the USA, and other research has shown that difference in culture can have an impact on the effectiveness of ‘simple’ Crew Resource Management (CRM) training. There were demonstrated rewards and benefits with performance and efficiencies being improved. 1100 hours of training and coaching was delivered to more than 26 nationalities across the full spectrum of roles ranging from drilling supervisor and OIM to the assistant crane operators & assistant drillers offshore, and where the majority of crews were non-native English speakers. However, as has been recognised in other domains, measuring these improvements is a considerable challenge and should not be underestimated despite the non-tangible gains observed in other domains. Finally, the paper will show that the development of WOCRM skills cannot be done via a ‘sheep dip’ approach. Furthmore, nationalistic cultures need to be taken into account when developing WOCRM training interventions; they need to be tailored to individual crew-members and specific teams. Finally, it should be noted that training alone is extremely unlikely to deliver the expected benefits and as a consequence, strong leadership and long-term commitment is essential, with a need to deliver coaching and continued development at the workplace and not just in the classroom.

The electronic Permanent Downhole Gauges (PDHG) has traditionally been used in the Karachaganak field to monitor downhole pressures and temperatures, for reservoir management. The overall performance and quality of the data from some of the Permanent Downhole Gauges (PDHG) installed in the Karachaganak field was not satisfactory. Hence, fibre optics has been investigated as an alternative technology due to the reliability, calibration and cost concerns related directly to the Permanent Downhole Gauges (PDHG). This paper will discuss the implementation and installation of the first fibre optic pressure and temperature monitoring system installed in the Karachaganak field. A dual fibre optic pressure and temperature system (rated to 200°C and 20Kpsi) was installed to a depth of approximately 5000m with a maximum inclination of about 35°. The metallurgy for the fibre optics system was Inconel 718 due to the presence of H2S. The surface equipment comprised of a Zone 2 rated Wellhead Data Acquisition Unit which has direct connection to the operation base providing ‘real time’ pressure and temperature updates (up to one second update rate). The paper will highlight some of the design and implementation considerations that were addressed to combat issues which had been experienced with more conventional monitoring systems such as reliability, accuracy and data communication issues. It will also describe the process that was undertaken to meet the stringent Kazakhstan Metrology requirements that are required to be obtained prior to the deployment of a subsurface measurement system. This process involved meeting the requirements for GOST-K for Safety and Quality and the Metrological Certificate which ensures that all measuring instruments are of stated accuracy and resolution and are acceptable to an accredited Institute of Metrology. It will discuss the detailed Factory Acceptance Tests (FAT) and System Integration Tests (SIT), as part of the critical planning process prior to the field installation. The paper will also cover the challenges during installation and subsequent use. The deployment data interface requirements and associated benefits during well stimulation, well testing and subsequent production will be described in full.

Seismic finite-difference (FD) modelling is a term that describes the propagation, recording and processing of virtual seismic waves through a computational model. It is an important tool for addressing a wide variety of questions related to seismic acquisition, processing and interpretation for the simple reason that seismic images are best assessed when the subsurface is well defined. FD modelling is particularly useful when data is to be acquired over targets that present complex imaging challenges, such as those underneath salt bodies or a highly heterogeneous shallow section (e.g. Regone, 2007; Kabir et al., 2009). This paper discusses the application of finite-difference modelling to the central part of the Azeri-Chirag-Gunashli (ACG) field offshore Azerbaijan (Figure 1) and builds on the earlier work of Crosby et al. (2014). ACG is a steeply-dipping NW-SE oriented anticline approximately 10 km wide and 50 km long. The targets reside within a series of Late Miocene stacked braided fluvio-deltaic sequences with intervening shales (e.g. Reynolds et al. 1998). Imaging is complicated by the presence of steep dips on the flanks and a highly heterogeneous shallow section including mud volcanoes, complex faults and shallow gas bodies at the crest. It is clear that any model must capture these details if it is to be useful. Historically, the principal limitations of seismic modelling have not just been computational, but have also resulted from the level of detail in the model itself. Models have either been constructed manually using a set of interpreted framework surfaces or derive their properties from existing seismic images (e.g. Regone, 2007; Kabir et al,. 2009). In the first case, reflectivity is often too simplistic; whilst in the second case artefacts and bandwidth limitations are introduced as truth into the model. A better approach is to simulate geological features directly when building the model. Two recent papers (Etgen and L'Heureux, 2013; L'Heureux and Etgen, 2013) present an automatic, probabilistic method for generating stochastic stratigraphy using a set of facies templates, and then morphing the resultant layering to structure. This approach can generate geologically realistic models to arbitrary levels of detail. Here we show the result of applying this method to Central Azeri, together with some preliminary synthetic seismic images.

The Azeri-Chirag-Gunashli (ACG) field is a giant oil development located in the Azerbaijan Sector of the Caspian Sea, consists of several stacked reservoir layers being produced through 6 platforms (Chirag, West Chirag, East Azeri, Central Azeri, West Azeri, and Deep Water Gunashli) and being operated under a Production Sharing Agreement (PSA). The ACG field is becoming more mature in its development and the need for artificial lift is becoming essential to maintain production and enable the startup of weak wells. Gas Lift is the artificial lift mechanism currently selected for ACG and surface facilities are designed to support that method. The availability of high pressure gas for injection, and the high productivity potential of ACG wells were key factors in the selection process. Not all of the older ACG well stock is equipped with downhole gas lift mandrels (GLMs) today. In order to retrofit conventional completions, the existing tubing is pulled from the well and a new tubing string with GLMs and a surface controlled annular subsurface safety valve (ASV) is installed, requiring around 30 days of rig time. This consequently delays drilling of new wells as only one rig operation on each platform is available. Overall, conventional recompletion is an expensive operation, and some wells don't have sufficient incremental production to justify execution of this high cost wellwork. Alternatively, coil tubing nitrogen lift can be used to start up wells without gas lift, but it adds additional risk to platform operations, takes additional operations' time and deck space, is expensive, and it is not practical for continuous use. In addition, completion running procedures did not allow for unloading valves installation during completion phase and use of more efficient venturi type orifice valve as opposed to square edged shear orifice. This creates a necessity for nitrogen lifting of new wells and unloading valve(s) installation at a later time adding to the rig time. In this paper, an alternative method of introducing Gas Lift to existing wells and modifications done to completion running procedures will be discussed. The proposed method utilizes a gas-lift insert system (GLIS) which includes a dual-packer with integral gas-lift valve that can be installed in the existing tubing using e-line. To mitigate the risk of annular gas release in the event that the tree is compromised, a Modular Surface Annular Safety Valve (MSAS) is installed, as installation of a conventional downhole ASV is not possible without replacing the tubing. The MSAS is a hydraulically actuated check valve that is installed in the valve replacement (VR) profile of the wellhead. Under normal operations it is held open by application of hydraulic pressure (using the existing platform safety system). This paper will discuss recent successful field results where GLIS was installed using only 7–11 days of rig time and results of new completions running procedure application. Results of a successful well restart producing 3 mbd of oil with 3 MMscfd of continuous gas lift rate being injected via GLIS and new well start-up utilizing benefits of updated completion design will also be discussed.

This paper presents the first experience of using a system for transmitting downhole data to surface (a telemetry system) based on wireless acoustic signal transmission during drill-stem testing (DST) in four carbonate reservoirs penetrated by an exploration well on Dolginskoye field in the Pechora Sea. Because no fluid would be recovered at surface during well testing, the job sequence program was optimized so that a full set of geological data could be obtained for each carbonate reservoirs in one trip. The purpose of a wireless acoustic telemetry system is to provide a communication link between downhole and surface equipment by means of acoustic signals passing through the well testing bottom-hole assembly (BHA) and enabling a two-way communication channel to be established so that bottomhole data can be received on surface in real time, and downhole equipment can be monitored and controlled. The system allows operators to adjust the well testing program based on bottomhole pressure data and to check whether sufficient amount of data has been collected for the well testing objectives to be achieved. Using a wireless acoustic telemetry system during dynamic well testing has many advantages compared to conventional testing with no downhole telemetry: bottomhole data can be received during job execution, operators have opportunity to monitor and analyze testing data and rely on a full set of representative data received in real time to make decisions for optimizing the job sequence program. The paper emphasizes the significance of receiving average formation pressure data during DST operations as it clarifies geological framework of the intervals under investigation and makes it possible to compare them with pressure data obtained by wireline tools when testing reservoirs with low porosity and permeability. The paper demonstrates a testing procedure optimization process which resulted in saving time on one well up to 36 hours and on other two wells – up to 24 and 48 hours, respectively, where acid treatments were considered unnecessary. For the first time, dynamic well testing were completed on the Russian Arctic shelf in four carbonate reservoirs without any fluid recovery on surface, under an optimized testing program. Considering a short navigation season, this technology is ideal for real-time bottomhole data transmission applications.

This paper describes the basics of the Targeted Bit Speed (TBS) technology and results of its application during construction of a group of wells at Urengoyskoe field located in Yamal-Nenets Autonomous Area, Russia. It highlights the advantages of TBS technology as compared to drilling with conventional BHA with a hydraulic drilling motor. It also compares various BHA configurations incorporating the TBS system. The Targeted Bit Speed technology is designed to improve well drilling efficiency. The TBS technology is based on a conventional bent-housing positive displacement motor (PDM) with measurement-while-drilling (MWD) tools. TBS technology delivers the same advantages as rotary-steerable systems enabling full 3D directional control with continuous drillstring rotation. In those cases when the required dogleg severity cannot be achieved with TBS technology, the system's operation can be suspended without retrieving the BHA to the surface with further directional drilling by conventional PDM orientation method. This paper describes the results of well construction at Urengoyskoe field, where the TBS technology was used by the operator to drill S-shaped wells with a horizontal displacement of over 1,000m. This paper focuses on directional control improvements, increased rate of penetration (ROP) and rotary drilling share achieved by the new system. Information provided in the paper applies to the first wells drilled in West Siberia by the TBS method.

In Oil Wells the design for each feasible artificial lift method is determined before running the economic analysis to better determine the efficiency of a particular installation. Consideration of the applicable artificial lift method helps to generate the necessary information for the net present value (NPV) analysis. In this paper, a study is carried for economic comparison of the wells with same design production rate considering two artificial lift methods i.e., ESP (Electrical Submersible Pump) and rod pump. In order to increase the operational window in general, units with expected higher run life and robust construction are preferred. Therefore, in this paper firstly, it is discussed for rate comparison between conventional beam pump and unconventional extra-long stroke rod pumping units. Secondly, simulation result of ESP for the same production rate as is achievable by unconventional rod pumping unit is discussed and thirdly an economic comparison is carried between them. It will be clearly seen for the economic variation by production either through Unconventional rod pump or ESP lift method for same target rate and same pump setting depth. To use the NPV comparison method, it is important to have a good idea of the associated costs for each system. This requires to evaluate each system carefully for the particular well and be aware of the advantages and disadvantages of each method and any additional equipment (i.e., additional costs) that may be required. Therefore, in this paper comparison is carried for the operating expenses (OPEX) for two replacement choices—a smaller-size ESP and a long-stroke pumping unit, and its NPV. Comparative plots are obtained for rate Vs cost to generate NPV at different depths and corresponding rates. The results obtained is a valuable data base for economic comparison between ESP and rod pump for same rate wells.

Multi-cluster staged fracturing is an effective method to exploit shale gas. Field observations reported some clusters did not generate fractures. X formation in Sichuan Basin is a 3000m deep shale reservoir. The horizontal stress ratio (Shmax/Shmin) is around 1.4 which is therefore difficult to generate fracture network. How to enable all fractures propagate effectively from each cluster and generate enough stress interference to enable fracture network is of critical concern. This paper established a 2D fracture propagation model based on finite-element method to simulate multi-cluster fracturing. The fracture propagation model couples seepage-stress-damage theories to simulate fracture propagation. The cohesive element is used to simulate the forming of fracture, and the filtration from fracture to matrix is taken into consideration. This model is used to study three fractures propagating simultaneously from three clusters. Different cluster spacing cases were simulated to investigate the fracture geometry and the stress field. When the cluster spacing is 10m, 20m and 30m, the simulation shows that the length of the middle fracture is severely restricted; but for the side fractures, the length is over propagated. When the cluster spacing is 40m and 50m, balanced propagation of all the three fractures is achieved. In 10m, 20m and 30m cases, the stress field shows that in front of the middle fracture, there is a high compressive stress area caused by over propagated side fractures, and this stress could prevent the middle fracture from propagating. So the range of optimized cluster spacing is reduced to greater than 40m. In order to increase the possibility of generating fracture network, the cluster spacing should be small to create high rock frame stress between the fractures. By considering the fracture geometry and stress field, the optimized cluster spacing is 40m cluster. This paper presented a method to optimize the cluster spacing by both considering the fracture geometry and stress field. Cluster spacing optimized by this method could enable the effective propagation of all main fractures and increase the possibility of generating fracture network.

Mooring Integrity Management has gained much interest in recent years as the failure rate for FPS mooring systems has been found to be significantly higher than expected. Existing mooring integrity management practices have not provided adequate protection against such failures. This paper provides an overview of recent advancements in the understanding of fundamental degradation mechanisms applicable to mooring systems and improvements to mooring system integrity. Advancements in the understanding of mooring system degradation mechanisms will be explored through reviews of recent Joint Industry Projects (JIPs) that have looked at corrosion mechanisms for chain and wire rope, as well as remaining life assessment for corroded chain links. Recent advances in understanding of wire rope birdcage formation and degredation will also be presented. Improvements to the approaches to management of mooring integrity will be provided by an overview of the DeepStar® supported industry study that has developed Model Guidelines for Mooring Integrity Management (MIM) for permanent mooring systems (AMOG, 2013). These Model Guidelines serve as the foundation for future implementation of risk-based inspection planning for mooring systems. The framework for a risk-based inspection program can be used by the operator to meet the risk profile of the individual facility as well as corporate and regulatory guidelines. The guidelines identify the required practices at each stage of the mooring system life cycle in order to minimize the risk of degradation mechanisms arising from design, construction, installation and operations practices. Fundamental to the reliability of this methodology are the means to estimate the long-term degradation processes, such as corrosion, wear, fatigue and constructional disturbance, and the commensurate reduction in residual strength capacity and degraded fatigue endurance. The former of these aspects has been the subject of two JIPs, which have advanced the understanding of corrosion and wear processes (SCORCH JIP) and the commensurate reduction in strength and fatigue endurance (Chain FEARS JIP). The latter, constructional disturbance, is the subject of a proposed JIP, leveraging observations of degredation with numerical techniques. This paper summarizes significant contributions to the understanding of the key causes of mooring component degradation and improved techniques for the effective management of mooring system integrity.

This paper illustrates varying situations where the high-expansion hanger has proven to be a viable and valuable solution for reservoir analysis and optimization. Difficulties associated with acquiring accurate data using modern completion designs or new exploratory methods to optimize producing resources are also discussed in addition to solutions provided using the high-expansion hanger. A new high-expansion gauge hanger is deployed on slickline or coiled tubing using a non-explosive setting tool, for completion and reservoir analysis during well testing. It can be positioned anywhere in the casing for through tubing and/or rigless operations. The high-expansion design provides a generous bypass flow area to increase accuracy of data recorded. A unique slip design enables reliable set in highly scaled or corroded pipe. Precise placement of downhole gauges on slickline reduces cost and improves accuracy of reservoir and production analysis for improved recovery and efficient well placement. It is becoming more important to ensure the accuracy of reservoir performance data acquisition to maximize asset production and extend the life of the well. By using strategically placed sensors to accurately record critical information from multiple forms of testing and reservoir enhancement techniques, accurate data gained during testing phases ultimately leads to the best flow regime design and successful reservoir optimization. Modern completion design or reservoir stimulation techniques are effectively evaluated using data acquisition, aiding the development, refinement, and implementation of such techniques. Anchoring sensors in wellbores without decreasing flow can be challenging when introducing new techniques or modifications; these flow-rate conditions can prevent the determination of production at the time and rate that could maximize production and revenue of the asset. This paper examines difficulties associated with accurately acquiring downhole pressure and temperature data in complex well completions as a means to analyze reservoir properties and ultimately optimize the asset recovery. The high-expansion hanger provides a means for precise placement of downhole sensors in more challenging completions during well testing. Being able to precisely position pressure gauges, sampling tools, or other memory-based logging mechanisms is of great value. By using the slow consistent power of the downhole electrical power generator tool as a setting tool, the gauge hanger provides increased reliability and creates a secure anchor point, regardless of scale buildup or location. It can be run on slickline, electric line, or coiled tubing (CT), providing multiple solutions.

This paper presents a complete integrated asset model for gas planning and, in particular, the handling of stranded gas during exploration. Uniquely, it models a gas network from the reservoir, right through to product allocation based on contractual obligations. It back-allocates through the network from the market, to ensure accurate supply and product tracking. We show how this type of model provides unprecedented confidence in field evaluation and gas planning. The market-based approach to integrated asset modelling that we used includes an optimal amount of information to deliver a fast, accurate solution. Oil and gas exploration activities do not usually involve planning for stranded or associated gas. Many discovered gas reservoirs are left undeveloped due to a lack of scenario analysis during the exploration phase. A fully integrated gas planning approach is required for effective field development planning in a timely manner. This has been a subject of intense research and development in recent years. Stranded gas reserves can be effectively developed using proactive market planning and strategic gas exploration guided by an integrated gas planning approach. As such, our model includes reservoirs, platforms, facilities, pipelines and markets to effectively understand the network deliverability. In this paper we defined multiple scenarios for bringing up gas from reservoirs, through the facilities and delivery point, right up to allocation of resources to meet the market demand. The case study deals with a market-based approach for modeling 40 gas reservoirs and associated gas products from nearby platforms. The practical constraints such as condensate handling capacities, compressor systems, and contract gas quality are integrated into the model analysis. The unique, fully integrated reservoir to market approach to IAM we demonstrate in this study provides a real breakthrough in E&P companies’' ability to model and run scenarios against their complete gas network in a relatively very short time. In particular the back-allocation from the market provides confidence around their ability to meet their contractual sales obligations and enables product tracking through the whole network.

This paper is a case study of a well intervention performed by PETRONAS Carigali Sdn Bhd (PCSB) in Sarawak region to investigate and rectify a breach in well integrity. The review and discussion demonstrate that the intervention not only ensured compliance with existing well bore risk management guidelines but also reduced operational rig cost and enabled increase in production. The paper identifies the aspects of what appears on first view to be a straightforward well integrity diagnostic process, but which on deeper evaluation exposes the wider and acute impact of the outcomes of such a diagnosis. The nature of the diagnostic technique is examined, and the interrelated impact on PCSB HSE requirements, platform operating efficiency, and field-wide production. The well intervention and the subsequent targeted rectification made possible by the precise nature of the diagnosis, enabled PCSB to bring this well back online and restore its gas production. This gas production is vital for several of the gas lifted wells in the field. Restoration enabled PCSB to increase field production significantly. The study concludes that accurate, reliable and rapid integrity diagnostics should not be evaluated as only relevant as a means of HSE management but also a means of cost management and in sustaining or increasing overall production.

This paper portrays how drilling project costs can be reduced significantly, through the use of Risk Impact Amalysis, which is vital in the current era of unprecedently low oil prices which puts pressure on the whole chain of oil and gas services. New ways of thinking and inventiveness are required if we are to keep drilling as opposed to stacking rigs which is happening at an alarming rate particularly on land in the U.S.A. If the cost of drilling cannot be reduced further, rigs will be stacked, several "cold" and the lucky ones "warm’. This paper desrbibes how, through focused risk anaylsis, a 10,000 rated rig was allowed by the authoriesto drill as opposed to the more normally required 15,000 psi requirement.