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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.

Zonal isolation is an important thing to acquire good cement integrity. One of many ways to evaluate this is by running Cement Bond Log (CBL). Well condition prior, during, and after cement placement contribute high impact on the result of CBL. Aside from that, temperature and pressure changes also give significant outcome to CBL result. In this paper, some improvements wereapplied and the logging results showed significant impact on zonal isolation compare to previous well. Objectives of this paper include improvement applied on case studies to obtain good zonal isolation and no remedial cementing required, emphasizing on applied cementing best practice recommendation, and introducing expanding agent in order to recover micro annulus. Well integrity is a vital element to have long well life cycle. The paper describes the enhancementfrom poor zone isolation in previous well to be better in next well and this became one of best practices of cementing design and execution for Operator. Improvement in mud removal was done by adding spacer volume with high concentration of turbulent spacer. Cement slurry had expanding agent in the system and smart retarder which provided better compressive strength. Improvements in cement system were seen in faster compressive strength build up and ability to recover micro annulus. Linear expansion result from expanding test is 80 μm in 7 days, which is sufficientto cover micro annulus that has happened before in previous well. The designed slurry was also supported by using more centralizers in execution. Quality check was done by measuring rheology of drilling mud and spacer. Cementing job was executed with no issues and following job program. Evaluation of cement job supported with the playback pressure data. Result of CBL result showed that good bonding was achieved on upper and lower side of interest zone.

Smart Auto Gas Lift (AGL) refers to a downhole system that utilizes gas from a gas zone or a gas cap in a well to lift oil below or above the gas zone in the same well. This paper illustrates a novel AGL intelligent completion design approach including candidate screening, pre-drill feasibility study, sensitivity analysis, and followed by the completion installation and production operation practices for the first two (2) successfully completed AGL wells in Malaysia. In the candidate screening process, a novel design approach was used based on a 3D numeric single wellbore dynamic model forecasting method. Firstly, candidate screening was performed for the application suitability of AGL in the candidate reservoir. The key screening factor includes the identification of the source of AGL gas, either from the associated overlaying gas cap or independently from another layer of non-associated gas, estimation of gas pressure and oil pressure, estimation of volume of available AGL gas and longevity of gas reserve throughout oil production life, and considering the reservoir structure and drive mechanism. Secondly, single well prediction modelling analysis was performed to evaluate candidates' dynamic performance on production rate, water cut, gas oil ratio (GOR) profile and pressure depletion over time. This is to make sure designed AGL completion will meet expected various production dynamic responses during the entire life of well. The next step is to conduct production snapshot nodal analysis for the appropriate choke size design for AGL downhole flow control valve. Those dynamic results from the single wellbore prediction model becomes important input for nodal evaluation to simulate changing reservoir conditions at different stages. Finally, various sensitivity analyses on layer properties and valve setting depth are followed to ensure that the AGL valve choke sizing design range is flexible enough to cover expected reservoir uncertainties and to be effective over the entire well life. Based on above design and analysis approaches, a specified range of AGL valve choke opening were designed for T field candidate wells and smart AGL completion system was installed successfully and safely in two wells by end of 2014 without any health, safety and environmental (HSE) issue and AGL related non-productive time (NPT). The production and well test data were available for production performance surveillance, and the dual permanent downhole gauge system (measuring pressure and temperature in both the tubing and the annulus) at gas zone enabled the continuous auto gas injection monitoring at real time basis. This paper discusses AGL well design approaches, justifications, best practices and lessons learned regarding completion installation, well clean up and production operations to give a general guideline for AGL implementation in this area in the future.

Most of oil fields in China have stepped in the development stage of high water cut. The accurate measurement of downhole water cut is the key to master the developing status, upon which injection and production adjustment could be implemented to improve oil recovery. This paper proposed an electromagnetic wave based water cut meter, which can realize full-range measurement of the water cut with high resolution and accuracy. The measuring sensor is equipped with two coaxial cylindrical conductors, the oil-water mixture flows between the two conductors during the measurement. When electromagnetic wave transmits in the coaxial sensor full of mixed fluid of water and oil, the wave phase shifts regularly. The water cut of the mixed fluid is calculated through the measured phase variation. Based on the analysis of polarization principle, dielectric property, transmission law, and the circuit implementation, this paper established the mathematical model of electromagnetic wave phase variation, and determined the frequency of electromagnetic wave. Then an electromagnetic wave based water cut meter was proposed. Through simulations and experiments, the paper studied the influence factors of measuring accuracy, including the mixed fluid's temperature, salinity, pollution to the conductors, and emulsive state. The temperature and salinity show associated effects on the measuring result. If the salinity is low, the response of water cut meter decreases with temperature rising. If the salinity is high, the response is just the opposite. Under different emulsive states, the response frequency of the mixed fluid exhibit same tendency, although the frequency value may show some difference. The oil films adhered to inner or outer conductor both give rise to measuring errors, while the pollution to the inner conductor produces more obvious influence. The response characteristics of water cut meter were also summarized in the paper and the compensation methods to eliminate or reduce the interference were confirmed. At present, in most cases, the downhole water cut are measured during well logging or separate-layer producer testing. This paper proposes an electromagnetic wave based water cut meter, which can be equipped in the downhole production regulator and realize automatic production adjusting.

This paper is a case study of field data, assessing the impact of a well integrity survey on an on-going development drilling programme, enabling critical management of an unexpected shallow gas risk. The results and conclusions presented are applicable to the diagnosis and risk management of shallow gas zones and their impact on well construction, design and integrity. The well Operator experienced a severe loss of well control during drilling operations in the Western Block of Talang Jimar field in Sumatra. The field is mature and the well was considered routine in a series of more than 200 drilled over the past 50 years. A kick occurring at a relatively shallow depth around 300m was completely unanticipated. It was judged critical to further drilling to investigate the location and extent of the charged interval. This would identify HS&E and operational risks to be mitigated by modification of both the on-going drilling plan and the well design. The clearest and most precise information was required. When active surface gas venting was discovered at an adjacent well, an ultrasonic annular integrity survey was commissioned to determine the subsurface source of the gas. This ultrasonic survey deploys a number of sensors on wireline in the well, the most important being a passive ultrasound detector. The paper describes the survey technique in brief, the results of the successful survey and the modifications made to the well and mud-weight design to manage the shallow gas risk and the benefits for the drilling programme. The new results presented reveal annular flow outside surface casing with clarity, and the paper explores the underlying reasons for this clarity and its potential benefits for shallow-gas applications. Field data is presented to support the conclusions reached. The methods and technology described in the paper will be of interest, as they should be widely applicable to shallow gas integrity diagnosis, whether a surface gas vent or sub-surface cross flow, in both onshore and offshore applications. Such diagnosis may enhance drilling and production HS&E performance, reducing the risk of well-control incidents.

The paper describes the reservoir management experiences of Kerisi field after seven years of production. Kerisi field is located in Block B of South Natuna Sea and comprises five separate reservoirs in three geological zones. Forty seven percent of the reservoir hydrocarbons are located in the Upper Gabus Massive West (UGMW) reservoir; optimum production from this formation is expected to be reached by injecting gas at the gas cap. The source of injected gas is from all five Kerisi reservoirs and the nearby Hiu field. The liquid hydrocarbon production from UGMW and the production/injection of Kerisi – Hiu produced gas in this formation is of high importance to the future development stage of Kerisi – Hiu field. The initial reservoir management strategy was to optimize oil value with injection while meeting gas sales requirements. Both gas sales commitments and injection targets were honored with high Kerisi – Hiu production and the strong performance from other gas fields. With time, other gas fields became depleted faster than expected. Thus, it was decided to reduce gas injection rate in UGMW and produce more Kerisi and Hiu gas to increase gas sales volumes. The reduced of injection rates improved short term economic of the fields, but the effect to reservoir and long term economic benefit still needs evaluation. This paper will (1) show the impact of varying injection rate at UGMW to the overall Kerisi – Hiu field future production, include oil, gas, condensate, and LPG, (2) discuss an updated – improved reservoir management strategy, and (3) present an economic evaluation of the updated reservoir management strategy for the Kerisi – Hiu fields. The purpose of the paper is to share lessons learned in the evaluation of historical performance, data acquisition and monitoring, static and dynamic modeling, history matching, prediction of future performance, and the dynamics of reservoir management strategy which support future profitable opportunities.

In order to enhance the recovery of heavy oil, the paper mainly studies the in-door experiment and numerical simulation of the steam-air combination flooding. The experiment contains 7 sub-experiments: steam flooding, steam-air combination flooding including mass ratio of air and steam from 1:32 to 6:32. After the research of different mass ratio of air and steam, we can see that heavy oil recovery will increase firstly then decrease as the mass ratio of air and steam increases. When the mass ratio of air and steam is 2:32, the oil recovery ranks the highest, which is up to 68.67%. Furthermore, temperature showed at the thermodetecter is almost the same as steam flooding. When the mass ratio of air and steam exceeds 4:32, the oil recovery factor of steam-air combination flooding is less than that of steam flooding. The temperature at the end of the sand packed tube is far less than that of steam flooding. Through numerical simulation study based on the condition of Qi40 Block in Liaohe Oil Field by CMG, when mass ratio of air and steam is 1:32, oil recovery remains the highest. However, when mass ratio of air and steam is more than 3:32, oil recovery of steam-air combination flooding is less than that of steam flooding. Since differences exist between in-door experiment and numerical simulation, the detailed results are different. However, the tendency of the heavy oil recovery varies with mass ratio of air and steam remains the same. At last, a field test of Qi40 Block in Liaohe oil field is introduced in the paper to validate the experiment and numerical research.

When a wellbore is completely or partially filled with gas and work over or drilling operations are to be carried out on the well, it is necessary to bleed off the gas and replace it with liquid or mud to maintain well control. The replacement of the gas in the wellbore by liquid is commonly done in small stages with gas being released after each stage. This procedure usually requires a long time and could lead to adverse consequences. The method proposed in this paper will enable engineers to determine in advance the exact volumes of liquid necessary to pump into the well and the exact volumes of gas to bleed off after each injection so that the bottomhole pressure always stays above the formation pressure but below its fracturing pressure. The method takes into account the integrated pressure calculation due to a real gas column in the wellbore. Thus, the variation of the gas deviation factor with pressure and temperature of the gas in the wellbore is taken into account. The results obtained assuming real gas behavior vs. ideal gas can be significantly different in the number of stages, volumes calculated and pressures especially for deep high pressure and temperature wells. Two calculation procedures for the volumes and pressures are presented in the paper. These procedures are outlined step by step in the paper. The procedures are fast and eliminate the need for unnecessarily small injected liquid volumes and remove the element of guessing and the danger of unforeseen consequences.

History matching and production optimization are the important keys in reservoir modeling. Reservoir geology plays a crucial role in these complicated processes and the oil and gas operators highly demand for a fast, accurate and effective integration of geology and reservoir engineering that is still limited in the past. This paper aims to present: (1) a modeling approach that automatically integrates geological modeling software, a reservoir simulator, and history matching and optimization software in a closed-loop; (2) the advantages of an assisted history matching approach; (3) a robust optimization workflow based on multiple geological realizations. This new approach was successfully applied in a Brugge reservoir. We first present a systematical workflow of the integrated modeling that allows us to capture the crucial effects of geology. Based on this approach, multiple geological realizations are geostatiscally generated for history matching, robust optimization and uncertainty assessment. We utilize the benefits of coupling the geological modeling software, the reservoir simulator and the optimization tool together. The Designed Exploration and Controlled Evolution optimization method is used to perform the history matching. In the history matching process, the optimizer invokes geological software with new variogram parameters to calculate the reservoir properties. Finally, a robust optimization approach based on multiple geological realizations is introduced to overcome the current weakness of optimization based on single realization. The closed loop modeling approach is proven a powerful tool to improve the modeling quality and reduce the time and engineering efforts for capturing the critical effects of reservoir geology in complex sandstone reservoirs. Using this closed loop modeling, we successfully perform an assisted history matching of the secondary waterflooding process. This method effectively accounts for the uncertainty of geological characteristics in terms of facies proportion and spatial distribution. The properties of each facies were controlled by both blocked data histograms and the vertical trend. The results of history matching show that the misfit of objective functions was reduced from 16.45% to 6%. Finally, we optimize the rates of thirty injection and production wells over the life of a reservoir, with the objective to maximize the average NPV based on the geological realizations that the history misfit is less than 7% rather than using a single realization. The results show that the robust optimization significantly improve the expected NPV and reduce substantially the risk associated with geological uncertainties. This paper presents an efficient modeling and optimization approach under geological uncertainties by integrating various simulator's available in the industry. The innovative closed loop modeling workflow together with an assisted history matching and robust optimization provides a means of optimizing recovery and assessing uncertainties of both secondary and tertiary EOR processes.

One of the main challenges of drilling in the Central Andaman Sea offshore Myanmar is the mitigation of overall well integrity risk arising from weak top-hole formations. On a well drilled by one operator, conductor integrity was lost due to cratering and loss circulation while cementing which eventually led to having to re-spud the well. Almost all the offset wells drilled by the operator in the same field experienced losses in the top section interval. To meet integrity objectives for both exploration and development wells, the cementing strategy in certain cases must consider alternative solutions in addition to conventional Class G cement. In a recent project executed for one operator the cementing philosophy for the entire surface sections therefore had to be fine-tuned to incorporate the proven Optimized particle-sized distribution methodology. A proprietary coarse material made from glass beads was introduced as part of the slurry design, being used for the first time in Myanmar to further improve cement properties. On the development wells the optimized design called for pumping 10.5ppg High-performance Light-weight cement (HPLWC) lead slurry, together with a standard Class G tail. To meet operational integrity objectives, planning and risk assessments were put in place by the service company and the cementing programmes were developed to incorporate necessary mitigations against the identified risks. Plans were put in place to handle the implicit logistics requirements. Careful attention was paid to the execution given the downhole pressure sensitivities, all slurries were mixed and pumped with a degree of relative precision. This paper summarizes the design and implementation of the cementing operation which contributed positively to meeting well integrity objectives. Apart from operational success, expectations which hitherto factored in possibility of top-up jobs were exceeded; for the exploration well the critical zones were covered with good returns to seabed observed on all the cement jobs as monitored by ROV. Hard cement were tagged and drilled out from the shoe track in each case and well operations progressed without any loss of integrity issue. The paper aims to demonstrate that incorporating technology can help to improve well delivery and reduced lost time. Approximately, 18 cement jobs have been executed on the project - all successfully done. Out of these 4 top-hole cement jobs involved the use of the High-performance Light-weight (HPLWC) technology described in this paper.

This paper portrays the methodologies utilized to yield potential "barrier reserves" of 936 million BOE from an Operator’s mature fields’ portfolio. The paper reviews the whole project in overview and will also go into detail for one particular asset to appraise readers of the pertinent details associated with how each particular methodology yielded the "barrier reserves" it did, including the economic value and risks associated with each mature field.

This paper examines the safety trends influencing and shaping the oil and gas industry. From rising local content requirements to increasing shortage of skilled workers, rise in unconventional Oil and Gas to an increasing number of frontier oil producing countries, the growing role of Operational Excellence and the most common causes of incidents in the Oil and Gas sector, this paper will discuss facts, figures and case studies from around the world. The paper was developed using secondary research based on industry reports such as the International Association of Oil and Gas Producers' (IOGP) Annual Safety Performance Indicators report to provide an analysis of fatal incident rates, total recordable injury rate, and lost time injury frequency. The research also referred to country profiles published by the US Energy Information Administration (EIA) including energy outlooks, analyses and projections. Information was culled from annual reports of international oil companies, technical papers published by the Society of Petroleum Engineers (SPE) as well as white papers by industry leaders, think tank groups and consulting firms. While the presentation offers a bird's eye view of the safety industry at large, it delves deeper into safety issues outlining the scope of the various challenges and how they influence Health, Safety and Environment (HSE) management. It highlights the importance of heeding lessons learned from catastrophic incidents as well as the adoption of industry best practices and integration of Operation Excellence into the core business operations to prevent disasters. Concerns on unconventional production and the need for regulatory frameworks in emerging countries indicate that regulatory bodies need to catch up and fast track research efforts to regulate the unprecedented growth and expansion of the industry. When taken together as a whole, the global safety trends indicate that investments on safety or the lack thereof has a huge impact on business continuity and sustainability. This paper was developed to give safety practitioners a better overview of the challenges, opportunities, new developments and trends shaping the global Oil and Gas industry.

The oil industry is still an interesting sector to invest as the world's current oil reserves and production continue to show an upward trend despite the fact that oil is unrenewable resource. There are various methods to assess the value and the risk of investment in the upstream oil industry such as described in the SPE Paper from Widjadono (1993), Dharmadji (2002), Rajan (2008), and Craig (2004). However, these assessments are frequently done separately resulting in two different perspectives of investing in a country; the value and risk. This paper aggregates the study of value and risk as a single result in order to assist oil companies analyzing and comparing the country attractiveness objectively. Two approaches with completely different inputs and methodologies are used to assess the country risk. The first is the country risk score method which focuses on the country risk index observed by independent parties, such as corruption, terrorism, ease of starting business, etc. The second method is the Damodaran method which relies on financial market data of the country such as equity market volatility and country credit default swap rate. As a result, this paper will compare the combined value and risk results and analyze if the result from the two methods are validating or conflicting each other.

It is widely accepted that a project is successful when it is finished on time but unfortunately, due to many reasons, in Indonesia, a large number of upstream oil and gas projects failed to meet their original contract time. The success of the delivery of upstream oil and gas projects in particular becomes pivotal as oil and gas production steadily declines each year, and Indonesia's economy and revenue are highly dependent on the upstream oil and gas sector. For example in 2012, 15 projects with the combined maximum throughput capacity of 1,062 MMscfd and 23,060 bopd were initially expected to go on stream. However due to a number of reasons, 12 out of 15 projects were delivered with the combined maximum capacity throughput of 430 MMscfd and 5,600 bopd only. As mandated by the government, the Special Task Force for Upstream Oil and Gas Business Activities in the Republic of Indonesia (known as SKK Migas) is responsible for developing upstream oil and gas projects as part of its main function in terms of maximizing national oil and gas production. This paper presents our experience, as a government agency, in managing all upstream oil and gas development projects in Indonesia. This paper also reviews the major project and construction management challenges experienced in Indonesia. All information and data were acquired and gathered throughout a series of intensive monitoring with all Production Sharing Contractors in Indonesia: meetings, discussions, site visits and written reports. All this information was further analyzed and categorized into several main factors that affect the delay of oil and gas development projects based on original Plan of Development and Engineering, Procurement, Construction and Installation contracts. The findings show that the main critical factors that cause delays in Indonesia are contractor performance, logistics, government approval and permit, societal, environmental and commercial issues. In addition, this paper also explores and provides some recommendations to reduce the impact of delays on oil and gas projects in Indonesia.

PTTEP in the Gulf of Thailand faced costly challenges while conventionally drilling several narrow operating window ultra high temperature (ultraHT) wells with formation temperature up to 220°C (428°F). In the ultraHT sections, the operator encountered serious ballooning issues that resulted in severe non-productive time (NPT) and difficulty reaching well total depth (TD). Additionally, formation pressure uncertainty in the steep pressure ramp region posed additional drilling challenges due to high risk of influxes. PTTEP decided to utilize managed pressure drilling (MPD) to overcome the complex ultraHT wells. The strategy involved designing a hydrostatically underbalanced mud weight to prevent ballooning and to enable optimal drilling flowrates. The automated MPD was used to continuously maintain bottomhole pressure (BHP) above pore pressure to avoid influxes. Furthermore, the MPD system was also used to safely identify formation pressures by performing static flow checks (SFC). Dynamic formation integrity tests (DFIT) and dynamic leak-off tests (DLOT) conducted while drilling accurately identified the losses limit and ballooning gradient. At well TD, special rollover procedures were implemented to displace trip mud weight in order to safely control the well prior to pulling out of hole, taking into account extreme thermal effects on bottomhole pressure (BHP) reduction. PTTEP was able to drill through the narrow operating window and avoid problems associated with typical ultraHT condition, including ballooning, loss and influx events. Moreover, MPD allowed the operator to drill efficiently while identifying the actual drilling window to establish wellbore pressure boundaries. Importantly, the operator was able to log the well to obtain the necessary geological data. As a result, the operator cut well costs by 50%, a total of USD 5 million, and saved 20 days of drilling time. The paper will share the success story of MPD application in drilling challenging ultraHT wells in the Gulf of Thailand. The paper will describe the drilling solutions to solve the well problems and the lessons learnt as part of knowledge sharing.

Sajaa gas field is one of the oldest fields in the Northern Emirates operated by Sharjah National Oil Corporation (SNOC) where Petrofac currently holds accountability for the Sajaa asset operations until November 2015. Since 1982, this mature asset has experienced increasing gas recoveries with declining reservoir pressures subsequently leading to condensate banking and liquid loading problems. Many techniques had therefore been adopted including drilling of multilaterals, plant inlet compression and foamer, but the effects were short lived as the reservoir pressure declined further. This paper deals with the latest production enhancement technique involving field wellhead compressors applied on the asset to increase its deliverability and longevity. This project involves the installation of 12 Well head compressors which effectively aim to include the entire inlet from the field through these units. A total of 18,600 HP of compression has been introduced throughout the field with these fuel gas powered reciprocating compressors, including a primary separation unit on each skid. They have principally been able to reduce the flowing WHP to as low as 15 Psig associated with a reduction of DeltaP across the wellbore, thereby reducing the effect of liquid loading and aiding to an increase in the primary condensate and water recovery. The scope of this paper is the analysis of the Full field compression (FFC) project providing an overview of the installation methodology, performance of the wells and the incremental effect of the project which exceeded the forecasted gain, along with troubleshooting from a subsurface point of view. Finally using the Integrated Asset Model to link the subsurface performance to the surface gain and forecasting the increment of reserves associated with the FFC in a mature retrograde carbonate reservoir environment. An insight into the factors influencing the compressor performance and the optimization techniques employed during the 2 year long project is also presented.

The objective of this paper is to examine the recent improvements in packer and plug design, minimizing packer element extrusion. Based on these changes, operators now have more intervention options at reduced risk. While applicable to both new completions and interventions, this paper will focus on intervention technology. For many years, extrusion gap has been controlled primarily by the use of a "Gauge Ring" as a packer back up. While successful, this approach dictates a large OD packer or plug to minimize extrusion gap. As our industry has developed more tortuous well bore geometry, large ODs have led to running and pulling problems. These designs have also prevented many operators from recovering failed zones. Water encroachment, gas migration and failed sand screens have often been dealt with by re-completion. Options were limited to inflatable systems, long elastomer or umbrella types of plugs. Horizontal completions further reduced that to only inflatable solutions, due to umbrella systems dependency on cement. Recent developments in high expansion products have opened up new opportunities to recover from these types of problems. High expansion elastomers and new design packer back-up systems allow for actual V-Rated packer, plug and straddle systems. With this benefit, comes the added value of a retrievable system. Intervention work always carries with it the risk of failure. Recovery from a failed intervention can sometimes be a return to the original work-over plan. The most successful of the new systems incorporate expanding packer back-ups. High expansion types of systems are now being used for: Horizontal sand control in failed screens Packer failure recovery Straddles, straddles with stand-alone screens Zonal isolations, (including straddles) P&A work This type of equipment allows for the recovery of a failed intervention, as well as recovery from a change in wellbore dynamics. If the intervention team set the high expansion style system in the wrong place, they simply recover that and re-run at the correct depth. Should wellbore changes dictate a change, all or part of that system can be recovered and modified to accommodate the change in pressure/gas/water/sand. In conclusion, the ability to reduce extrusion gap, while at the same time reducing OD of completion / re-completion components, brings operators new avenues of success with reduced risk. Exciting new applications include, high expansion style straddles with sliding sleeves, Smart valves, and chemical injection systems.

This paper will be discussing about drilling operation of the Matindok Gas Development Project (MGDP) of PT Pertamina-EP that was developed in order that the gas consumptions of Eastern Indonesia territorial could be well fulfilled. Lost circulation & kick problem with major content of H2S and CO2 that were potentially expected to be drilling hazard at Manahaki formation of the field, therefore it would be a great challenge to be discussed on this paper. Matindok Field had been developed since the POD (Plan of Development) was approved in year 2008 after this Matindok gas field was discovered with predicted IGIP of 347 BCFG. There were totally 7 delineation/development wells that were drilled under MGD Project. The latest well (Well #8) was completed and tested with the results of 10.671 MMSCFD, 149.99 BCPD from Menahaki Formation and 20.23 MMSCFD from the other previous completed well (Well #6). Since to drill the Matindok wells have consisted of several drilling hazard (such as, shallow gas, lost zone and high pressure zone) therefore the drilling program of the wells required a thorough preparation on drilling engineering (i.e studies and evaluations) before PT. Pertamina-EP able to prepare all the matter concern with the execution of drilling operations. Lesson learned that was encountered on the earliest wells that were drilled had been evaluated in order eliminated all potential drawbacks as experienced, Therefore drilling performances can be improved. Detail operational drawbacks and evaluations process to results significant drilling performance improvement from one wells to other consecutive wells will be discussed in detail on this paper. Drilling cost of the Well #6 indicated significant improvement had been well achieved. Drilling Division of PT Pertamina-EP had spent only around 66 % of the approved AFE budget of the well to complete the well and zero non-productive time (NPT) record was achieved when drilling the well (Well #8).

This paper describes main processes used for removal of CO2 from natural gases and some results of under R&D technologies of acid gases extraction from natural gases, including the method of 3S-technology (SuperSonic Separation technology). There are various methods of acid components extraction from the natural gas: adsorptive, adsorptive, membrane, cryogenic and their various combinations. All mentioned technologies are notable for necessity to use a large number of accessory equipment, including bulky one that leads to the high capital investment costs and great operational costs, and also to the costs for restoration of adsorbents/absorbents, clearing of membranes, etc. These circumstances make the existing technologies inapplicable in terms of cost efficiency. At the same time, a significant progress was recently being made in the development of new low-temperature processes of extracting CO2 from natural gas. Low-temperature processes are specially promising in processing of gases with high CO2 content. Several low-temperature processes of CO2 removal are presently known: –Ryan Holmes method;–Controlled freeze zone method (CFZ);–Cryocell method (Cryocell);–Sprex method (Sprex);–Gasdynamic separation of gas mixtures (3S-separation). All 5 above mentioned low-temperature processes of acid components extraction will be considered and analysed in this paper. While the main focus is on the analysis of 3S-separation technology. 3S-separator is a low-temperature supersonic separator, based on natural gas cooling in a supersonic swirling flow. Supersonic flow is implemented using a convergent-divergent Laval nozzle. In this nozzle, rapid cooling of gas takes place due to the conversion of flow potential energy into kinetic energy. This workcontains a detailed description of 3S-technology. Someexistential schematic diagrams of devises based on 3S-separation will be presented in this paper. The advantages and limitations of this technologyhave been investigated during the study. Currently3S-separators have been successfully operatedat severalgas processing facilities. Experimental studiesof CO2 separation from naturalgaswere carried out onthe test unitwith the3S-separator, designed for 6000 nm3/hour gas flow. Duringtests it has been shownthat the technologymakes possible theseparation of CO2 inthe carbon dioxide crystallization zone. The performed tests demonstrated that it is possible to achieve less than 3% mol CO2 concentration in the inlet gas.

During the exploration and production of oil and gas resources in Kuwait Oil Company, a wide range of risks and dangers are present frequently, which have the potential to result in a major incident. This paper describes a case study on sharing vital lesson leant from major incidents (work related/ Non-work related) that occurred in recent past. All these incident have thoroughly been investigated and intricate underlying causes and root causes of these incidents been identified. A lot of new lessons from these incidents were identified which are very vital for drilling industry to look upon and learn from these in order to avoid these learning from own experiences on the cost of loss of life/property. Various relevant corrective actions have been described in this paper in order to prevent the occurrence of such incidents in future. The outcome from this paper is intended to improve the competency of the employees and increase their awareness of the sake of incidents prevention. Kuwait Oil Company has focused on reducing the probability of similar incidents occurring in the future by adopting generative culture in sharing lessons learnt among all employees and conducting various significant initiatives for all HSE aspects. Other Drilling Industry in the region may also be befitted by adopting the outcome of this presentation being in similar nature of work environment.

Reliable and fast prediction of fractured well performance is vital for asset evaluation and prudent field development decision making in unconventional, low permeability oil and gas reservoirs. Simple low cost techniques such as decline curve analysis are ill suited of properly accounting for extended transient flow regimes. Numerical simulation techniques on the other hand are unrivaled in capturing geological details and high accuracy in fluid flow description. However, they suffer from high computational expense and often too little relevant data is available. Our objective is to develop an efficient semi-analytical solution that combines the advantages of speed and accuracy from both techniques for forecasts on single well, pad and even field level. Contrary to conventional oil and gas reservoirs, the tight reservoir characteristics allow for the application of analytical solutions to predict the behavior of fractured wells. The depth of investigation is small with spatial property variations having limited influence considering the large local pressure gradients. Fluid flow is mainly of transient nature and less dominated by multi-phase flow effects within the reservoir. Moreover, the typical configuration of an individual well with multiple fracture stage, entire pads with multiple wells or even entire assets allow the application of the superposition in space, providing a cheap means for accurate solution for multi-well problems. This paper presents a transient semi-analytical model based on a tri-linear formulation. It accurately captures fluid flow to a single or multiple fractured wells over the entire life cycle of production, from early linear flow to pseudo-steady boundary driven flow. It is applicable to oil or gas reservoirs with permeabilities ranging from nano-Darcies to approximately one milli-Darcy. It is capable of handling both the vertical and horizontal well type, with either single or multiple fracture stages respectively. Well-bore, stage and pad configurations can be freely parametrized. A tubing head pressure boundary condition is incorporated to model production from those wells more realistically. For shale type reservoirs, a desorption process is incorporated. The model is particularly suitable for quantitative evaluation of field development alternatives involving a large number of fractured wells. The accuracy compared to a high resolution numerical simulation model generally exceeds 90% with a computation speedup factor in the order of one hundred or more. Besides conventional benchmarking with a numerical reservoir simulator, actual field production data from the Marcellus and Eagleford shale wells shows the utility of the new solution. Being both fast and accurate, the technique presented in this paper is ideal for supporting high quality, cost efficient decision making which is crucial in the current low oil price environment.

A method for predicting torque and drag has been developed which is based on statistical learning models and which utilizes parameters routinely measured while drilling. Real time prediction of torque and drag during drilling has particular significance in on-the-fly rig floor operational modifications and in overall drilling optimization. These statistical methods are readily incorporated into real time drilling optimization procedures, first through a passive diagnostic tool, and subsequently through an integrated real-time control loop.This paper presents statistical learning techniques such as bootstrapped regression, random forests, and support vector machines for prediction of downhole torque. An analysis of the aforementioned methods is carried out to evaluate computational efficiency of the processes. The statistical package R has been employed for processing and visualization of data and for displaying results. A comparison is made to real time ROP prediction carried out in previous work, to assess the relationship between predicted torque and ROP. A method is proposed to use classification techniques for predicting whether drilling is proceeding at the optimal level.Torque values were accurately predicted with all three methods discussed in this paper. However, scalability of the methods must be considered, owing to the increased computational efficiency that is required. Computationally efficient and robust systems are of high priority for field applicability. To that end, ensemble techniques were analyzed along with the aforementioned methods and runtimes were evaluated for all of the methods employed. Results show that this method can be incorporated into real time drilling situations, with attending low runtimes. Development of more accurate methods will require additional computational power and the use of ensemble techniques. Classification proves to be a good technique whenever optimization is required, as indicated by real time predictions. Classification techniques illustrated in this paper explore the viability of various options for correcting undesirable drilling performance.This paper presents state of the art statistical learning techniques for predicting torque and drag during drilling. Previous torque and drag calculations using finite element models provide a good cross reference with this statistical model for indicating operational anomalies. Unexpected values of torque may forecast imminent drilling problems. These methods can be utilized for prediction of drilling problems and proactive methods for avoiding them, and applied in optimized drilling procedures.

The paper begins with highlighting the limitations of traditional safety management efforts and importance of addressing human factors. Paper will then focus on human factors that lead workers to behave unsafely and then explain the psychology and rationale behind the BBS Approach and how it helps addressing human factors. It will highlight merits of BBS Approach to Safety (Proactive vs. reactive), which uses top down leadership and bottom up engagement to close the ‘behavior gap’. Then, the paper will start with a brief overview of BBS Efforts in KOC in Phase 1 and 2 with DuPont (Preparatory) and Phase 3 "On the Job" BBS implementation through Coaching & Mentoring with Quality Safety Edge. Then, it will explain the (a) Rational behind Phase 3 BBS Implementation Approach and give (b) An Overview of BBS Implementation Process (Observations & feedback on critical behaviors-Area team data review & action planning-Steering Committee review & action planning-Recognition & celebrations). It will also highlight the Role played by BBS/HSE Videos in success of BBS Implementation. Facility-Specific Observation Check List developed based on at-risk behaviors that caused incidents will be presented, followed by presenting of Safety Survey Questionnaire developed for Safety Surveys and Observation Check Lists developed for measuring the level of compliance with select HSE Procedures (Permit to Work, Job Safety Analysis, Emergency Response and Driving) and explain how HSE Behavioral Indicators are calculated. Then the paper will highlight the improvements achieved in KOC Facilities through BBS implementation by contrasting Post-BBS Implementation Statistics vis-a-vis Pre-BBS Implementation Statistics in respect of Safety Survey Findings, Level of compliance with select HSE Procedures (PTW, JSA, ER and Driving) and HSE Behavioral Indicators on KOC Overall basis. Changing behaviors is a long drawn process requiring consistent efforts. Yet KOC has achieved significant improvements as Post-BBS Implementation surveys & statistics reveal. KOC has gained immense firsthand experience in implementing BBS in Middle Eastern Culture, highly resistant to change. The paper shares KOC's experience, not only what all we did right, but also what/where all we could have done better.. As human behavior is a persistent common issue, such sharing will be of immense practical value to Oil & Gas companies, operating in Middle East or any other part of the world.

The Kuwait Oil Company is developing the North Kuwait Jurassic Gas fields in order to increase domestic gas supply. The reservoirs are difficult with deep, poor quality reservoirs under high pressure containing H2S and CO2 leading to significant challenges. KOC entered into an Enhanced Technical Service Agreement (ETSA) with Shell in order to benefit from IOC expertise and to optimize the development. Some 40 Shell staff work with KOC. A core element of the ETSA is to build and enhance KOC's staff competencies to develop the North Kuwait Jurassic Gas fields. This professional competencies development program is done through the application of various training and coaching activities. KOC has an established and well-structured competence assessment and training regime for all staff under their employment. Shell, with its wide experience in sour and High Pressure/High Temperature (HPHT) gas field development, is well placed to complement and build on this important competency development process. Shell has embarked on a journey to shorten it's time-to-autonomy by transitioning from traditional classroom training to providing structured development programs including on-the-job-training, blended learning and coaching. The paper will describe how training and coaching activities were selected for KOC's North Kuwait Jurassic Gas team, how they were implemented and monitored, and what the critical success factors were. Shell's training and coaching program to the North Kuwait Jurassic Gas team have started five years ago with a steady increase of activities year-on-year. The multiple years' implementation of the North Kuwait Jurassic Gas competency development program have allowed for learnings, review and fine-tuning of the program. The paper will address the most important elements for a successful training and coaching program in this unique partnership. This contains of four elements, the role of management and business; type of training and coaching event; staff's own involvement and training program management. The paper will show how an IOC supports an NOC to enhance staff competencies in a challenging technical area, how this training and coaching plan is being managed and executed and what are key elements to consider.

The field under study is an elongated NE-SW faulted anticline which has a main axis length of around 25 km and a width of approximately 6km located onshore UAE. The main hydrocarbon accumulations occur in the Lower Cretaceous-Thamama Group. This group is comprised of a series of carbonate reservoirs with well-developed porosity, but low to moderate permeability. This paper discusses the implementation of acquiring Formation Pressure While-Drilling (FPWD) applied for better understanding and mitigating the geological structure uncertainties. The results were used to obtain accurate reservoir pressure measurements while drilling horizontal wells that intersected multiple fault blocks. Formation pressure measurements acquired while drilling (FPWD) have numerous applications including mud weight optimization to reduce drilling risk, control well placement in pay zones to maximize reservoir contact (MRC), and for better reservoir management by evaluating the connectivity between different fault blocks. This paper will discuss the theory and the operational sequences of the FPWD tool as well as the results of some case studies in the implementation of the FPWD runs in an onshore Abu Dhabi carbonate field.

The last decade has seen the initiation, start-up and ongoing development for major oil and gas production projects requiring processing of extremely sour gas. Projects in the UAE and CIS states (particularly Central Asia) require processing of well fluids containing up to 10 mole % CO2 and 23 mole % H2S, with the potential for future projects to see the H2S level increase further. These projects are being designed to treat and process flows of up to 1,000 MMscfd alongside production of oil and/or condensate, as well as NGL/LPG recovery. The world scale processing of sour gas leads to the largest ever sulphur plants installed, with total plant capacities up to 10,000 TPD of elemental sulphur. Kuwait with the Jurassic gas projects is embarking on major sour gas processing and is ideally placed to benefit from the experience and strategies developed in these mega projects. This paper summarizes a selection of the key sour gas mega project metrics and outlines some of the areas where the very high H2S and organic sulphur content of the well fluid, and the high ambient temperatures, either impacted the design of the process units or required additional design features. The technical discussion in this paper uses information gained from Fluor's experiences on several sour mega projects and covers: Inlet gas conditioning to ensure there is no hydrocarbon condensation during the gas treating stepRemoval of H2S, CO2, COS, and mercaptans from the gas phaseCondensate/oil treating options for organic sulphur removalThe design of the world's largest Sulphur Recovery and Tail Gas Treating trains

The Greater Burgan Field is located in southeastern Kuwait, covers a surface area of about 800 square kilometers and is ranked as the largest clastic oil field in the world. The field comprises six main reservoir units, namely Wara Sand, Mauddud Limestone, Burgan Sand Upper, Burgan Sand Middle, Burgan Sand Lower and Burgan Fourth Sand, stacking on top of each other. The Wara Shale acts as a barrier separating Wara from the massive sands of the underlaying Burgan formation. However, extensive faulting does allow communication between the Wara and the Burgan Sands. Production was initiated from the Greater Burgan Field in early 1946. As the field has matured over time, the reservoir pressure has declined in certain areas, with associated reduced productivity. The reduction of wells’ productivity, combined with the increasing water production, has necessitated improved oil recovery (IOR) initiative in order to support the Kuwait Oil Company (KOC) 2030 strategy, sustaining a corporate target oil rate and ensuring high recovery from Burgan reservoirs. This paper describes the modeling effort in designing the Wara Pressure Maintenance Project (WPMP). The WPMP is the first major full-scale waterflood project implemented in the Greater Burgan field. The management decision was based on the fact that Wara has experienced significant pressure decline after 68 years of primary production. Weak edge water drive, combined with poor reservoir connectivity, has resulted in deteriorating productivity along with creating secondary gas caps in some areas. In 2005, design for a pressure maintenance project (PMP) 2 via a peripheral waterflood was initiated to arrest pressure decline and improve oil recovery. Indeed, it became a major component of the Greater Burgan Field Development Plan (FDP) and is now entering the operation stage after 10 years of planning and facility construction. The Greater Burgan FDP is supported by a massive sub-surface modeling project. It started in 2009 with the sequence stratigraphy model (Phase-1) followed by geological model (Phase-2) 6 and dynamic model (Phase-3) 9. All modeling projects were conducted by reputable consulting firms with significant KOC hands-on participation and project management. The three modeling phases were concluded in 2013 and a simulation prediction model has been developed as a premium FDP reservoir management tool. In this paper, we focused on the modeling of the WPMP which was built meticulously and comprehensively to produce an optimal development and operation strategy. This includes project phasing, waterflood pattern design, producer/injector locations, drilling sequence, polygon setup for voidage replacement ratio (VRR) control, and constraints for good reservoir management practice. Sensitivity on constrained and unconstrained cases was included to evaluate future facility requirement. All in all, a robust simulation model to optimize Wara waterflood performance and ultimate recovery.

KwIDF is a complex cross-domain solution consisting of a fully integrated infrastructure which supports field instrumentation, automated workflows and ergonomically designed collaboration solution. This paper describes virtualization technology and associated improvements in processes that will improve the Digital Oil Feld infrastructure resources and allow KOC's Corporate IT Group with tools to achieve more flexibility in delivering business critical data that translates into decision-ready information and collaborative support. After three years of operation, data volumes are increasing rapidly with multiple workflows driven by multiple applications and the current infrastructure is not adequate to provide optimum performance. Added to this, complex workflows are planned for the next stage of development which will demand performance that the current system will not be able to deliver. Though there are dedicated servers for each application, it is difficult to manage the application servers and storage. Therefore, it is essential to build a robust infrastructure for the current and future environments which will only become more complex with the onset of advanced workflows and exponential increase in the volume of data. This paper describes the virtualization solution for Kuwait Digital Integrated Field infrastructure which will improve the utilization of resources, enable high availability and provide better disaster recovery solution. The solution will include the SCADA industrial network and the corporate user network which will allow KOC to achieve measurable business benefits such as reduction in the cost of IT Infrastructure while improving performance and reliability

Agile methodology (Agile) has become a revolutionary tool that continues to help IT companies today develop innovative products that are rated high in quality and customer satisfaction. The Agile model has proved successful in reducing defects, delivering valuable results quickly, and encouraging collaboration among teams. This paper will discuss some of the basic concepts of Agile to show the value of its application in digital oilfield projects. The Agile methodology is based on concepts that have been extensively used in the software industry. Complete principles defined in The Agile Manifesto will be discussed in detail along with the different Agile methods and processes that are typically used in some IT companies today. This paper will also strive to provide details that will help readers relate the concepts of Agile methodology to the digital oilfield processes present today. This will help organizations that are implementing digital oilfields to decide whether Agile can help make their processes run more efficiently. The Agile model is defined by a set of 12 principles that is readily available in a document called, The Agile Manifesto. Agile concepts, such as: Sprint, Scrum, Iterative Planning sessions, User stories, Backlogs, and other practices, will be defined to provide a clearer understanding as to how the Agile process works. Along with these concepts, the Agile process will also be illustrated and detailed in order to give the reader an understanding of how a product goes through a typical Agile workflow from beginning to end. With the current shift of utilizing IT technologies to support and develop digital oilfield operations, Agile concepts will be increasingly important as it encourages constant collaboration and interaction among teams over processes and tools, figuring out responses to change over simply "following a plan", and giving importance to working results over presenting documents in meetings. The novelty of the Agile methodology is to provide a possible solution to making IT processes more efficient and value-driven in the petroleum industry, especially in the area of digital oilfields, as it aims to increase collaboration among team members and deliver high quality results quickly.

Stage tools have been commonly used in North America for monobore completions to optimize economics. By cementing back the vertical and build sections of the wellbore, the requirement of the intermediate casing and liner hanger packer can be eliminated. An operator working in the K-1 carbonate formations of a massive field in eastern Saudi Arabia was examining a unique application of a stage tool to effectively cement and isolate a water-producing build section of a sidetracked lateral wellbore. The well incorporated a liner hanger packer with a multistage completion system. This paper will describe the distinct operational challenges encountered and how they were solved by redesigning an existing stage tool. The well profile and construction specified that the liner had to be hung above the sidetrack point. Therefore, it was critical that the sequential operation of running the lower completion string, setting the liner hanger, releasing the liner hanger running tool, setting the open hole packers, cementing the upper liner section and then setting the top packer be completed with tremendous accuracy for a successful job. The operator selected a stage tool with a secondary contingency closure mechanism that did not limit the inside diameter through the system. This mechanism would ensure that all stages could still be stimulated if the secondary closure option was required. The use of the stage tool with a liner hanger system required some design modifications; the typical single foam plug, used to displace cement and close the tool in the standard version of the stage tool, was not an option. Instead, the operator required that a separate drill pipe dart and wiper plug assembly be used to displace cement through the drill pipe and the liner. The stage tool was, therefore, redesigned to close with a wiper plug launched from below the liner hanger packer. After open hole conditioning, reaming and logging, the lower completion was run to setting depth and all equipment functioned without any issues. The problematic water producing zone was cemented and isolated and the stage tool was closed without the need to use the secondary closure mechanism. The stage tool was then milled out, leaving the well ready for stimulation. The redesigned tool enabled the operator to effectively cement the upper wellbore with no inside diameter restriction for stimulation. This paper highlights the first introduction of cementing stage tool technology in conjunction with a multistage completion system to an operator in Saudi Arabia and the tool redesign required for accommodating a liner hanger packer in the wellbore. This method could also be applied to any type of lower completion such as sand management screens, inflow control devices or in conjunction with slotted or solid liners as an off-bottom cementing application.

At the early phases of EOR developments, small scale pilots are commonly used to obtain information of the EOR field development mechanisms. The lessons learnt from these early pilots are subsequently used to de-risk and improve the full field developments. In initial phases, well and reservoir surveillance plays an important role to increase the understanding of the effectiveness of the EOR processes in the various reservoirs. Well-planned and executed reservoir surveillance has proven in the past to de-risk and optimise production and ultimate recovery from reservoirs significantly. Successful projects are characterized by a high level of cross discipline integration. This paper discusses the important field development decisions of Miscible Gas, and Chemical projects, that have been based on well and reservoir surveillance results that will be presented in this paper. A clear strategy is presented to select surveillance strategies dependent on the field development decisions that need to be taken. Moreover, field case examples of these decisions are presented in the remainder of the paper. For the chemical injection project in a clastic field a new workflow was developed to analyse well-tests of for polymer injection. The field management decisions to adapt rates, effective viscosities and change water treatment requirements are supported by an integrated modeling and surveillance effort. This fracture monitoring workflow plays a role in the regular pattern management evaluations to manage the field in a holistic manner. Two examples of a miscible gas flood will be presented. In the first one, the pattern geometry of a miscible gas flood was changed from an inverted 9-spot to a line drive based on surveillance information. Additional development opportunities and reserves were identified through extensive surveillance, performance monitoring and data gathering pilots. In the second example, we present the field outline with a surveillance plan, with magnetic resonance and other new saturation tools. Moreover vertical conformance is demonstrated to be measurable through distributed temperature sensing.

This paper demonstrates that selecting a gas processing concept that is robust against changes in predicted gas composition during the maturation of (associated) gas projects reduces the risk of schedule delays and cost creep while potentially presenting opportunities to deliver first hydrocarbons to customers earlier. During early project phases, the availability and quality of data on the specific field to be developed are usually limited. Consequently, project teams have often been left with two options when designing gas processing facilities. The first option is to rely on old data, data from well tests of questionable quality and/or data from analogue fields, if available, in order to form the basis of their design. This brings relatively high risk of having to redesign once higher quality data become available. Design alterations may delay the schedule to first oil/gas and lead to increased costs and erosion of the overall project value. The second option is to wait for new well test data to become available before starting work on the gas processing facilities. This approach, though preferable, can result in costly schedule delays and does not guarantee the delivery of accurate data on which to predict the gas composition and base the gas processing design. Appreciating this uncertainty is the first step in mitigating the risk. The second step is selecting a gas processing concept that is robust against flow and compositional deviations. In this way, the design of the gas processing facilities can go ahead at a low risk before full appraisal of the field is complete. This may enable parallel project phasing by starting the engineering procurement and construction (EPC) phase for the gas processing facilities during field appraisal. Shell believes that an effective gas processing line-up of an acid gas removal unit (AGRU) that utilises the Shell Sulfinol-X all-in-one amine technology along with a selective acid gas enrichment unit (AGEU) combined with sulphur recovery units (SRU) and sulphur dioxide (SO2) tail gas treatment provides the robustness to deal with high compositional uncertainty for the gas. The novelty in this paper is recognising that robust gas treating line-ups such as the one described above can have operational advantages and enable developers to secure their licence to operate by meeting emission restrictions. These line-ups can also have additional project execution/schedule advantages that add value to a project. Specifically, this paper will demonstrate that the small additional capital expenditure required for the proposed robust design is more than compensated for by the acceleration of the project resulting in an overall improvement to the net present value. Additional benefits to the project will be ease of operation, simplicity and ultra-low emissions.

By using Persistent and Daily Digital Oil Field Diagnostics techniques a KOC FD team transformed a 5 year closed well, into a 2000 mdb Oil Gain with a remarkable 0% water cut also been achieved. Historically wells completed in Complex & heterogeneous carbonate reservoirs always surprised the NOC NK FD team with distinctive behavior and anomalies, noting also that the NOC's North Kuwait field is on the threshold of embarking upon a strategic ambitious water flood expansion and a systematic increase in injection volumes. Within this process of increasing WI volumes the team realized that it is essential that producing wells are continuously analyzed with the latest Digital Field dynamic data and tangible decisions are made to manage the Voidage-Replacement Ratio. It was during this review process that Well-M was recognized to have a potential added value opportunity This paper outlines both DOF technical review and management process's used in transforming what was seen as a DEAD and closed well into a daily valuable contributor to the NK asset and assist KOC meeting its production goals. The paper closes in lessons learned and the next steps to embed this process into KOC's management processes.

The Kuwait Oil Company is developing the North Kuwait Jurassic Gas fields in order to increase domestic gas supply. The reservoirs are difficult with deep, poor quality reservoirs under high pressure containing H2S and CO2 leading to significant technology challenges. KOC entered into an Enhanced Technical Service Agreement (ETSA) with Shell in order to benefit from IOC expertise and to optimize the development. Some 40 Shell staff work with KOC. A core element of the ETSA is to bring to bear technologies that can be applied within the North Kuwait Jurassic Gas fields. These technologies may be processes, software or hardware. It was clear that the technology management and implementation needed to be structured and a Technology Taskforce was created for this purpose. The taskforce is managed by both parties of the ETSA and contains members of KOC departments who support the Jurassic Gas Asset as well as Asset members themselves. The paper will describe how the Taskforce operates and how the technologies are selected and are introduced into the workplan. It will also describe how technology implementation is measured. To illustrate the process examples of actual technology implementations will be given. The Taskforce has been in operation for 1-1/2 years and results to date show that technology implementations over the last year have increased significantly compared with the previous year. In addition it has made the process of technology implementation progress very transparent so that performance can be tracked on a regular basis and measured against Key Performance Indicators allowing remedial action to be taken if necessary. The paper will show that a simple but structured approach to technology management leads to tangible benefits both in the immediate speeding up of technology implementations but also making it more visible how further improvements can be made. This approach can be applied to any company in the industry allowing benefits to be widely realized.

Legislation, the environment, economic and corporate social responsibility are some of the key factors that are governing the recovery of flared gas worldwide. There is growing awareness of the issues associated with flaring and efforts are being made globally by operators and governments to minimise it. There are several technologies for reducing flaring at source or in a processing plant. The choice of technology depends on the economics of the project, frequency of flaring, infrastructure available and location of the producing facility. This paper covers innovative Flare Gas Recovery Systems using Surface jet Pumps and avoiding the use of compressors. Conventional Flare gas Recovery systems usually comprise of one or more compressors, which compress the collected flare gas and route it for further processing. The compressor design is critical and determines the system's capacity and turndown capability. However compressor based solutions can be quite large, complex and have high capital and operating costs. They are also very sensitive to changes in gas composition and MW. Surface jet pumps (SJPs) are simple, low cost passive devices that can also be used to recover flare gas. They use a high pressure (HP) fluid as the motive force to boost the pressure of the LP or LLP flare gas and deliver it for processing. The high pressure fluid that is needed as the source of energy or motive flow is usually gas taken from the discharge of a compressor or from the export gas line. However HP liquids, such as oil or injection water can also be used. Advantages of using SJPs include low cost, no moving parts, zero maintenance, zero power or fuel gas usage, small footprint and varying layout configurations. SJPs are well suited to liquid ingestion and to changes in process conditions (without affecting performance). This paper discusses the use of Surface Jet Pumps as an alternative to compressors for flare gas recovery and cites several case studies of where this technology has been successfully utilised. The design and operational criteria of SJPs, as well as the economics is also highlighted.

Waste water disposal wells have a set of unique challenges that accompany their respective stimulation treatments. Those challenges are mainly attributed to the sub optimal quality of the disposed water compared to typical injection water. A waste water disposal well has abruptly lost the ability to inject water. The subject well has been repeatedly stimulated in recent years. A full system QA/QC of the disposed water at the disposal wells has shown satisfactory results and compliances with environmental standards of water quality except for this well that ceased to inject. Well-A flowed back dead oil and exhibited an exceptionally high shut in wellhead pressures compared to offset injectors. To further identify the extent of oil inside the wellbore, a custom tailored gradient survey was conducted with multiple pressure points across the well interval. The gradient survey revealed accumulated oil columns in the upper part of the wellbore that was the main reason for the high wellhead pressure and contributed to the cease of injection. Moreover, the disposed water has tested incompatible with normal Treatment Approachs that were successfully used in the same field. Different stimulation approaches have been considered to restore and enhance those two disposal wells injectivites. The contemplated treatment designs were plain acid treatment, acid in diesel treatment, chemical diversion, emulsion breaking surfactants, organic solvents, and mechanical diversion. This paper presents the analytical diagnostic tools used to identify and comprehend the challenges associated with the disposal well in question and investigate probable causes for loss of injectivity using the inflow performance relation (IPR) and the out flow performance relation (OPR). Moreover, based on the findings of the IPR/OPR investigation, the paper would illustrate the best treatment to restore the injectivity of the well and delineate the decision making processes that have led to the successful flow back and stimulation treatment of the two waste water disposal wells using organic solvents and plain acid. Rigorous assessments of chemical treatment elements, treatment deployment methods, and stimulation techniques will all be thoroughly presented in this paper.

Drilling in North Kuwait presents significant challenges due to the hard rock in the overburden that needs to be drilled in large hole sizes en route to the targeted deep Jurassic reservoirs. A project was taken up in order to improve the drilling performance (especially Rate of Penetration, ROP) thought the hard layers located in three upper sections of the wells (28,″ 22″ and 16″) by implementing the "Drilling Efficiency Optimization" (DEO) methodology. DEO is an overall process to improve drilling performance by increasing ROP and bit footage through the utilization of efficient drilling practices throughout the planning, execution, and post-drilling phases. This paper describes the strategies, practices and "Driller Roadmaps" that were developed to improve ROP and drilled footage on the three sections of interest. The drilling parameters and results from three trials implementing the proposed improvements are also included. Field data demonstrates that by optimizing BHA (Bottom-Hole Assembly) design, bit hydraulics and drilling parameters through DEO process, the ROP was improved by over 70% on average in the three hole sections in which the trials were conducted. Also, due to the ROP improvement and longer bit run durations, a total of 17 rig days was saved. One bit established a new record for the longest 22″ TCI bit run ever achieved in North Kuwait (total footage: 2883 ft). Furthermore, the entire 16″ section was drilled using only two PDC bits, for the first time ever. The paper also provides recommendations on the next steps in DEO implementation to further improve drilling performance in North Kuwait wells. The insights provided in this paper will assist KOC in their endeavours to improve the overall drilling performance in their operations, especially drilling hard rock. The lessons learned have led to best practices being developed for the North Kuwait wells and serve as a valuable benchmark for projects located in the vicinity.

This paper aims at exposing oil and gas companies, contractors and service providers, to inspire and urge them to delve into the exciting and exponentially expanding world of MOOCs – Massively Open Online Courses. They have immense potential of vastly improving the process of workforce learning and knowledge growth. The benefits of the MOOCs are simply too great to ignore and continue to tread on the traditional training path only. Already several corporates have made a paradigm shift and redefined their training models. The paper presents the platforms, tools and opportunities available in both technical and non-technical fields, and how one can access these digital education processes from some of the world's best universities, professional forums and institutions, available often free of cost on the World Wide Web. This is the age of digital information, actively pursued by the current generation aptly named as "digital natives". The humankind has gone through several revolutions through the centuries and currently is undergoing through a very large, powerful and rapidly evolving e-learning transformation all over the world on the virtual platforms. Therefore, it is essential that everyone is made aware, understand and be part of these sweeping transformations in these learning mechanisms. MOOCs will empower the large community of oil and gas professionals to various self-learning technical, managerial, HSSE and personality development courses, while providing them accessibility sitting in their cozy confines of home. The Authors through this paper would like to bring and share their MOOCs experience to the SPE community. The paper discusses the essential attributes of the learning processes, and analyses both the traditional classroom based learning and MOOCs based learning opportunities. The focus is from a point of an engineer working in the oil and gas industry. However, the mechanisms and the approach methodology is beneficial for all the professionals, technical staff, managerial and administration personnel in the oil and gas industry as well outside it. The paper lists MOOCs providers, websites and resources under different categories such as universities based open source learning, institutional agencies, technical forums, libraries, general learning etc. where one can benefit from the tools such as MOOCs, video lectures, notes, books, standards, and technical spreadsheet based calculations etc. MOOCs have come into prominence very recently in the late 2012. Within these three years, they have caught the imagination of people, universities and the corporates alike defying the boundaries of nations, class, and abilities. It is no longer a fad but well established new trend of training and learning – anyone, anything, anytime, any rate, anywhere at no or insignificant cost. The authors are confident the resources and the information provided through this presentation will enlighten the oil and gas professionals with this new training trend.

Hydrogen Sulfide (H2S) can interact with steel tubular, such as drill pipe, and through the unfavorable combination of different factors a crack can initiate in the material and propagate until catastrophic failure, even with stresses largely below the yield limit of the material. The combination of tubular failures due to Sulfide Stress Cracking and the rising HSE concerns when dealing with sour gas has led the industry to develop new grades of drill pipe with enhanced resistance to SSC. Material selection for drill pipe in a sour environment is significantly complex, mainly due to the absence of dedicated international standard. Nonetheless, at a regional level the "Industry Recommended Practices" Volume 1 has been published in 2004 in Canada. The standard was created to insist on people safety, and provide specification and guidelines to manufacturers on material properties, quality control, testing and inspection of drilling products intended to be used in critical sour wells. Sour Service Drill Pipe as defined in the IRP have been used for a decade in Canada, as well as in other regions and continents, along with a variety of other proprietary Sour Service grades of drill pipe and BHA. This paper proposes a review of different field cases in the Middle East and Asia, as well as an outlook of the different practices for material selection and qualification guidelines which have emerged since the past 10 years. More recently, with the increasing demand of domestic gas in different part of the world, some highly sour oil and gas reservoirs are being explored with H2S contents beyond what could have been imagined a decade ago. To explore, appraise and eventually develop such fields, most of the time combined with complex well profiles or deeper reservoirs, significant technical challenges need to be addressed regarding drill pipe integrity and operations safety. This paper proposes a non-exhaustive review of the newest emerging industry trends as far as international standard guidance, regional normative initiatives, and new steel developments.

Sustainable development of a mature field depends on various factors, which can be categorized into well level and reservoir level. This paper is a summary of experience of various techniques used at well level and reservoir level. The objective is to sustain/increase the level of oil production and reduce watercut using various completion methods & pressure maintenance. This Paper will elucidate a Field Development Plan for a mature field. Several possible options were tested like 1. Possible workovers 2. Combination of Horizontal and Vertical wells based on firm and dependent locations 3. Infill short lateral wells 4. Optimal production rate to minimse pressure decline by limiting the gas production and hence putting a check on GOR 5. Water injection strategy 6. Intelligent Oil Field Completion using ICD (Inflow Control Device). For the purpose of testing the best possible course of action; the reservoir was modeled and history matching was done with satisfactory results. Prediction Strategy was then deployed at simulation stage. The financial analysis for all the prediction scenarios were also carried out using Net Present Value (NPV) method to check the feasibility as well as profitability of the various envisaged Production Strategies. Based on the analysis, the maximum recovery was obtained from a combination of infill wells and ICD completion, but on monetary grounds, the best case consists of workovers and horizontal wells to tap the oil from segregated pockets. In the end, a comprehensive and extensive comparison of all the possible way-through options are discussed with pros and cons of each one. A sensitivity analysis was performed on economic parameters (e.g. crude oil price, operating cost, Taxes, Royalty, capital expenditures) to analyze impact on various economic indicators. This Paper presents novel ideas into the ever expanding sphere of Field Development. It presents an extensive review of the various aspects of mature field development and their economic analysis. The field in discussion is Makum-North Hapjan which contributes around 40% of total production from OIL's fields in North-East India. It has been under production since 1993, with 62% of the production coming from horizontal wells.

This paper, produced for SPE Offshore Europe 2015, looks at the options available to the offshore fabric maintenance engineer when it is not possible or preferable to weld and discusses viable solutions using bonding or cold welding technologies. With the continuous corrosive attack of the environment, maintaining asset integrity offshore is a key challenge for operators looking to upgrade equipment or extend operation beyond the original design life. A crucial part of this process is ensuring the asset complies with all safety regulations, often requiring repair of the existing structure and new equipment installations. When carrying out such work, alternatives to welding or hot work offer significant advantages to the operator, for example, from a cost and scheduling perspective and for this reason cold bonding using advanced composite adhesives can often be considered. The paper aims to provide relevant information and data for reference by detailing case histories, from the initial design stage to installation and on-going inspection. Examples include safety critical equipment, such as handrails and accommodation modules as well as structural reinforcement to roofing and decks. In addition to the design of the bonded structures and joints, the paper also details other aspects to consider such as ongoing inspection and fire safety. By presenting appropriate test data demonstrating performance criteria the paper will explore the capabilities of modern composites to offer a variety of solutions for cold welding equipment. With the inclusion of case histories and physical test data, the paper endeavours to provide advice and guidance on the best practise when designing and installing equipment using composite technologies.

Typical workover operations involve the switching of subsea well barriers from permanent equipment to temporarily installed barrier systems. During workover activities additional operational hazards are introduced such as drive/drift off and compensator lockup which can have severe consequences including injury to personnel. To account for these operational hazards a workover system will have additional barriers. These barriers consist of instrumented and non-instrumented protective layers. The instrumented protective layers consist of safety instrumented systems (SIS). The safety instrumented systems fitted to a workover system can vary. Most workover systems consist of three common safety instrumented functions (SIF); Process Shutdown (PSD), Emergency Shutdown (ESD) and Emergency Quick Disconnect (EQD). The non-instrumented protective layers are made up from mechanical barrier elements for example the weak links. DNV GL on behalf of Statoil performed an analysis to better understand workover hazards and the barriers required to mitigate these. The aim of the work was to assess the effectiveness and suitability of the current safety barriers and to identify what additional functional requirements might be needed. This paper details the results of that work. A generic workover system formed the basis for the study. Hazards were defined through a hazard identification (HAZID) workshop and the effectiveness of the measures was evaluated through a Level of Protection Analysis (LOPA). This paper documents the results of a study to establish whether the current barriers used during workover operations adequately mitigate the risks. Despite having dissimilar operational modes, it is often expected that the workover system barriers shall be suitable for all operational modes. The results of this study show that some of the barriers in workover operations are not as efficient as perceived, in particular the riser weak link designs and manually initiated EQD functions.

One of the primary recommendations of the Wood Review is for Government and Industry to develop and commit to a new strategy for Maximising Economic Recovery from the United Kingdom Continental Shelf (UKCS). To achieve this recommendation several strategies are proposed. These cover the key UKCS areas which require enhanced development to ensure that the UK maximises the production of its assets. As part of the Technology Strategy, there is push to apply better reservoir management techniques on a cost effective basis. In order to manage a reservoir appropriately, the produced fluids have to be measured accurately. Typically in the UK, this is accomplished through the use of Well Tests and associated equipment – namely test separators supported by single-phase flow measurement technologies. Well test data is critical to operations in the offshore industry and covers a wide variety of applications. The data can be used to allocate produced fluids to particular wells either directly, or through verification of multiphase flowmeters. The data can also be used in the determination of reservoir size and in the positioning of new wells and installations. Another key use of well test data is in the optimisation of well production where well stream parameters can be altered to maximise hydrocarbon production levels. However, recent first-hand audit experience by DECC suggests that well test measurement systems may not be operating at their optimal levels. For instance, primary measurement elements (flowmeters) are often not removed and recalibrated on a routine basis. There is also evidence of flowmeters being exposed to two phase flows resulting in meter degradation. In addition, the interval between the testing of individual wells may extend to several weeks, with the flow rates between tests inferred by interpolation. The risk is therefore that these measurements may result in a measurement bias. This paper will present work completed on behalf of DECC into the current state of the art for well testing in the UKCS. North Sea operators have been questioned and their responses used to calculate typical uncertainties achieved during well testing. The significance of the uncertainty in measurement is highlighted through case studies into the impact on the applications that use well test data. Finally, alternative methods to current well testing practice are discussed with their expected impact on the UK offshore oil & gas industry. The submitted paper provides evidence and recommendations in line with the ethos of the Wood Review, as well as assisting industry to achieve the goals and step-wise improvement in performance, which the Review demands.

This paper will explore best practices for operators to make risk mitigation arising from process safety management (PSM) systems an integral part of efficient and effective operations. Operational risk arises from a complicated set of interrelated parameters and is viewed and managed in differing ways depending on the role and level in the organisation. The challenge is to simplify this complexity enabling all levels of the organisation to collectively focus on the major elements of risk that are important. Conceptual models like James T. Reason's Swiss Cheese barrier model or Bow-Tie models have been developed in an attempt to describe the inter-related nature of operational risk, but the industry has yet to develop operational systems that enable routine management of operational risk. Regulators are requiring companies with hazardous installations to implement process safety management systems. This has led to functionally focused management and process safety systems primarily aimed at compliance. Across the globe there are a number of process safety management models, from the Occupational Safety and Health Assocation (OHSA), California's Division of Occupational Safety and Health (Cal-OHSA), Safety and Environmental Management Systems (SEMS), UK Health and Safety Executive (HSE), the Energy Institute, and even the Tier 1-4 leading and lagging indicators from the American Petroleum Insititute (API). Furthermore, each company has established their individual process safety management or control systems to comply with or operationalise these models. Common to most systems is the concept of barriers, lines of defence, or layers of protection as a means of understanding how to protect operations from major accident hazards (MAHs). The challenge every organisation faces is how to relate the performance of their process safety systems in a meaningful way to the operatonal reality of the plant. Too often process safety leading indicators end up being focused on programme health and do not provide a forward looking view of how all the operational risk comes together where it matters most; frontline operations. To be successful in creating a sustainable business in hazardous industries, organisations need to collectively manage risk across their operations in a routine and efficient way. This requires a change in the dynamic between safety and productivity, where safety is not set against production and risk mitigation becomes an integral part of efficient and effective operations. Organisations need a holistic and common means of balancing risk against production at all levels of the operation. This paper will review existing PSM models, the challenge in relating PSM performance to the operational reality of the plant and how a new breakthrough provides a simple, elegant means of relating the collective performance of a company's process safety systems to the real cumulative risk impact on plant operations at any given point in time. This breakthrough is not a new process safety model nor an addition to existing process safety models. It provides the means to connect deviations from process safety performance standards to the operational reality of the plant through a common language of risk so that operational risk mitigation can become an integral way of achieving efficient and effective operations. By doing so it allows operators to understand their levels of MAH risk in a prominent and real time manner. MAH pathways through the fundamental barriers can be identified by combining the residual risk arising from deviations in any process safety systems. This provides a key indicator of MAH risk. This new breakthrough will allow people at all levels in an organisation to better understand the cumulative operational risk they are carrying at any given time which can be used to improve operational decision making. The benefits it delivers range from serving as an early warning system for potential MAH related incidents (allowing organisations to make proactive interventions), better prioritisation of maintenance to more informed decision making around risk and activity at the daily operations level.

Gangway equipped: offshore support vessels, intervention vessels, construction vessels, and other mono-hull vessels, capable of providing gangway access to offshore facilities in exposed sea areas has great potential. It is playing an evolving important role in making new marginal yield field development economical, reducing exposure to risk, and extending the life of the existing oil and gas infrastructure. Otherwise known as Walk to Work (W2W), this marine manning approach for offshore facilities can be used on a regular, fixed term, ad-hoc or exceptional circumstance basis. It is capable of providing significant benefits over existing provisions including: improved safety, increased workforce productivity, greater manning flexibility, and reduced lifecycle costs. The W2W vessel can range from relatively small, fast workboats, to large semi-submersible ‘flotels’ stationed alongside fixed platforms. Within this range, it is the mono-hull vessel where there is the greatest opportunity for the oil and gas industry to realise significant (currently unexploited) gain. Depending on the capability of the chosen vessel, a W2W solution may offer: gangway transfers, hotel, hospital, helicopter, rescue and recovery, subsea and splash zone inspection, cargo, crane, fabrication and other facilities. Offshore facility operators looking to improve performance by use of W2W; firstly need to fully understand their requirements; secondly, be open minded and innovative when looking for solutions; and thirdly, realise that to fully exploit W2W there are many aspects that need consideration to strike an optimal balanced solution. This paper presents the potential significant opportunities offered by W2W, and discusses the main areas that require consideration during the requirement definition and subsequent development of a W2W solution. The paper references a recently released guidance document covering W2W which was developed within a joint industry project with fifteen industrial partners (DNV GL W2W JIP 2015).

The ability to develop and use critical judgement defines and differentiates engineering excellence in our industry, yet it is one of the hardest skills to codify and replicate. This paper deconstructs the individual components and builds them into a framework that engineers and organisations can use day-to-day to develop consistently robust, pragmatic and timely decision making skills, whatever the situation. This is a key requirement for organisations to trust and empower people to perform effectively in increasingly unfamiliar contexts. Examples are given where critical judgement has influenced engineering situations and issues with the term ‘judgement’ are examined, including understanding the judgement of others, explaining your own judgement, importance of information to different experts; where the term ‘judgement’ is used to limit further engineering or analyses and the role of international codes and standards. After outlining the work of others, the paper provides a framework for critical judgement for engineers and other facilitators of judgement, such as managers or project managers, in the offshore industry and explains the key factors involved. These factors include scoping the problem, focusing on important aspects, practicalities, selection of methodology, sensitivity to assumptions, precedence/comparison, consequences of failure and pro's & con's and conservatisms & unconservatisms. Each of the factors within the framework can be used at any stage of a typical problem solving processs. It then outlines aspects of technical governance used within Lloyd's Register to consistently develop and manage judgement including technical authorisations and technical networks.

Organizations within the oil and gas industry have invested heavily in embedding competency programs into business framework and corporate cultures, expecting that they will be instrumental in terms of delivering superior business results by building and maintaining workforce capability. To execute this strategy, individuals should be engaged by reliably adopting principles and applying processes. However, with respect to accountability, individuals will choose to either adopt behavior that drives compliance or complacency for themselves and others. A “compliance mentality” involves individuals successfully applying competency program processes because they believe that developing, assessing, and documenting a true competence of the workforce will drive better business results. A “complacent mentality” involves individuals “ticking the box” or “chasing the numbers,” either unconcerned with how metrics are achieved or comfortable with mediocre quality because they believe that the extra time and effort is not worthwhile. The inherent challenges, therefore, are recognizing that complacency is likely and that a systematic methodology is necessary to (1) help mitigate risk by identifying nonconformance and correcting undesired behavior and (2) continuously improve the belief system of the organization. This paper discusses how a full-spectrum oil and gas service company, with more than 60,000 employees with competencies and 16,000 qualified raters, is ensuring that individuals adopt desired behavior by applying “verification”, a principle that is well-known but a practice that is not necessarily consistently applied throughout the oil and gas industry. This paper further highlights (1) how industry-recognized verification practices, proven at the local business unit level, have been reviewed and adapted to apply to a global competency program without creating undesirable burden, (2) how a layered approach to verification has been implemented, and (3) how this investment is producing the business results and benefits for all stakeholders in the competency program.

Intelligent well completions (IWC) have been installed in Malaysia since 2003, but only recently has this technology become widely accepted. This acceptance has resulted from recognition of values such as reduced capital cost, improved productivity, and increased ultimate recovery. Initial documentation on IWC capabilities was presented in 2012 (Masoudi et al. 2012). Since then, additional well and reservoir modeling has been conducted, and the added benefits shown from use of active flow control in these completions is documented, further improving IWC acceptance. This paper discusses the improvements gained from these studies, including the following: Determining if zonal flow control is necessary.Identifying which flow-control equipment is best-suited for the well.Determining the quantitative value in terms of productivity or injectivity and the estimated ultimate recovery (EUR) of installing flow control. Additionally, the importance of subsurface data gathering and the quality assurance and control (QA/QC) from that data are discussed, including the importance of identifying potential subsurface uncertainties during the IWC planning and design phases. Two intelligent-completion design examples from actual cases using the previously mentioned improvements resulted in successful completion designs. The design examples were from offshore wells that intercepted segmented or compartmentalized reservoirs and/or thin-oil rims. Additionally, the intelligent completion designs described in this paper were shown to be suitable for inclusion in sand-control methods, if necessary, as well as having the capability to address possible conformance issues. This paper presents the methodology used in the modeling as well as the successful end results anticipated by the operator(s) when using the IWC designs.

Following years of deliberation, the European Union released a Recommendation on unconventional hydrocarbons and a related Communication in 2014. Although these documents are not legally binding on member states, they are nevertheless of great significance as they indicate, for the first time, the current and likely future stance of EU institutions on the regulation of unconventional hydrocarbons. The paper will trace the origins and development of these documents, as they provide vital clues for the road ahead in European shale gas regulation. Given the long-standing absence of specific European regulation on unconventional hydrocarbons, a range of different views on the applicability of the existing regulatory framework evolved. The paper highlights the main pillars of the system, which constitute the foundations of the 2014 Recommendation on unconventional hydrocarbons. The paper will conclude that the European Commission resisted numerous calls for implementation of an unnecessarily intrusive and legally questionable set of new rules. Instead, it adopted a flexible and sufficiently open approach to unconventional hydrocarbons extraction. The 2014 Recommendation may hence be characterized as a successful balancing act, which leaves member states with considerable leeway for implementing their own regulatory strategies, while providing much-needed assurance for investors that Europe will not be “closed for shale business”.

A near-uniform well (production) inflow or (injection) outflow profile delays early water breakthrough and further decreases water cut which results in higher oil recovery. Field experience has shown that wells producing from, or injecting into, multiple layers and/or reservoirs benefit from an Inflow Control Device (ICD) completion's ability to reduce the in/out-flow imbalance along its length. The standard ICD completion design workflow involves selection of the “strength” of the ICD's restriction based on the incomplete knowledge of the reservoir that is available prior to drilling the well with several commercial softwares available for this. However, more complete reservoir data becomes available once the drilled completion zone has been logged and the data analysed. There follows a short period of time during which the engineer must judge whether the planned ICD completion design is “fit-for-purpose” or needs further consideration. The availability of a rapid ICD completion design methodology that does not require access to computationally demanding commercial software would be highly beneficial at this time. This paper presents a workflow which meets the above requirements. It extends our previous analytical approach to ICD sizing to directly relate the uniform-strength ICD completion design to the predicted heterogeneity of the open-hole inflow profile together with the consequent loss in well productivity from the ICD's flow restriction. The workflow combines a series of dimensionless, universal type curves and analytical solutions in a relatively simple and fast process to find the desired ICD design. A new completion design can be made immediately after drilling has been completed to provide the desired level of inflow variation from the latest predicted level of reservoir and fluid inflow heterogeneity determined by a “quick-look” evaluation of the well's log data. The same design procedure can be used to select ICD completion designs that are a compromise between two competing objectives: increasing the uniformity of the inflow profile and minimising the reduction of the well's productivity index that results from the extra pressure losses imposed by the ICDs. Two typical examples of the workflow's application are provided. The first one examines whether it is necessary to change the ICD completion design when drilling problems result in a reduction of the well's completion length. The second example evaluates the impact of the actual reservoir permeability profile being more heterogeneous than originally expected. The workflow's design philosophy was confirmed by commercial numerical simulators recommending the same ICD completion design in both cases. This work extends our earlier analytical approach to ICD sizing. This new ICD completion design workflow can be used by completion design engineers to rapidly analyse uniform-strength ICD completion design options and their consequences on well inflow performance without expensive computational resources. The underlying principles, assumptions and application area of the analytical model are fully discussed in the paper.