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IPTC 2014: International Petroleum Technology Conference
- Conference date: 19 Jan 2014 - 22 Jan 2014
- Location: Doha, Qatar
- Published: 19 January 2014
1 - 100 of 354 results
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Evaluation of True Formation Resistivity Derived from the Dual Laterolog-Rxo and the Induction-Spherically Focused Log
More LessThe problem of determining whether a Laterolog or an Induction is better suited to measure true formation resistivity (Rt) according to prevalent conditions is reviewed. The question of which deep resistivity device (Laterolog or Induction) should be run in a given well is investigated. To aid with this decision, examples are shown that cover a wide range of cases in both oil-bearing and water-bearing zones. True resistivity values derived separately from the Dual Laterolog-Rxo (DLL-Rxo) tool2 and from the Induction-Spherically Focused (ISF) Log3 are compared. The comparison helps determine the accuracy of the measurements made by each tool with respect to Rt. This also provides the capability to correct the resistivity values for the invasion to obtain Rt, leading to a more accurate evaluation of water saturation. Practical applications of both tool types, recorded over a limestone formation in three Middle East wells, are shown for a variety of situations in both fresh and salt saturated mud systems. The responses of the basic deep resistivity devices, deep Laterolog (LLd) and deep Induction log (6FF40), are shown for cases of shallow invasion, moderate invasion, deep invasion, and very deep invasion.
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Integration of Core and Log Data for Classification of Reservoir Rock Types in Minagish Reservoir of Greater Burgan Field, Kuwait
Authors L. Hayat, M.A. Al-Rushaid, K. Datta, S.H. Al Sabea, Y. Muhammad, E. Gomez, W. Clark, Y.Z. Ma and D.J. BondA detailed Geological and Petrophysical characterization was achieved in a stepwise approach as part of full field 3D Reservoir Modeling and Simulation study for Minagish reservoir in the Greater Burgan field in Kuwait. Foundation of Reservoir Rock Types (RRT) was developed in first step based on Mercury Injection Capillary Pressure (MICP) dataset. A combination of Discriminant Analysis and Indexed Self Organizing Map (SOM) was used for rock type classification using hyperbolic tangent method. To improve classification of bimodal Pc curves, additional pressure values at different non-wetting phase saturations were used in conjunction with above mentioned parameters. In second step, the available Routine Core Analysis (RCA) porosity, permeability data was grouped together based on common patterns to generate rock types in RCA domain. Blind tests in two of the cored wells revealed a conformance of 81% between MICP and RCA Petrophysical Groups (PG). In the final step of the process, petrophysical groups were propagated in log domain using available log measurements common in all the wells of the field. It was challenging to establish a high level of accuracy for PG’s in log domain mainly due to fine scale heterogeneity and inability of log data to capture rock fabric variation. This porosity estimate, coupled with rock type classification, helped to derive a continuous permeability log with a correlation coefficient of 0.89 validated in key cored wells. The porosity and permeability data in all the wells was incorporated in the 3D geocellular model after up-scaling honoring the unique, per rock type, Phi-K relationship. Modeled capillary pressure curves generated for each rock type in the core domain using MICP data set in 3 wells were used in saturation height modeling. The modeled equation was captured in the 3D geocellular model after populating rock types in the 3D grid to map water saturation for volumetric estimation.
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Use of Wireline Formation Tester Stress Measurements and Sonic Logs for Improved Geomechanical Model Construction of a Giant Depleted Gas Reservoir in Abu Dhabi Land: A Case Study
Authors K. Cig, H.I. Osunluk, M. Povstyanova, R. Masoud and K. AmariAbu Dhabi land has a giant gas field consisted of layered carbonate reservoirs. The long term plan of the field has been to produce the reservoirs with the safest maximum depletion. A detailed geomechanical study was undertaken to identify changing field stresses and to understand the possible reservoir rock collapse mechanisms. The foundation for any 3D geomechanical modeling is 1D Mechanical Earth Model that includes elastic and strength properties, overburden stress, pore pressure and magnitude and direction of horizontal stresses. The input data for 1D modeling is openhole logs (density and compressional and shear sonic logs). Image data, caliper logs, pore pressure and closure and breakdown pressure measurements are necessary to calibrate the models. To improve quality and reliability of the 1D MEMs, Abu Dhabi Company for Onshore Oil Operations (ADCO) requested lab measurements to calibrate elastic and strength rock properties and decided on pore pressure and stress measurements in one of the upcoming wells. Wireline Formation Tester (WFT) technique was selected to provide pore pressure, as well as closure pressure to calibrate magnitude of minimum horizontal stress directly and breakdown pressure to calibrate magnitude of maximum horizontal stress indirectly. Acquired compressional and shear sonic logs allowed building continues properties, pore pressure and stress profiles. The integrated study yielded calibrated stress profiles and enhanced geomechanical modeling for the reservoir intervals. The measured closure pressure indicated significant magnitude variations of the minimum horizontal stresses across production units suggesting existing of stress barriers at various levels. The amount of stress anisotropy at particular reservoir intervals was determined. The stress profiles indicated good fracture containment at various levels and identified potential applications for injection or multi-stage fracture design in vertical and horizontal wells for efficient reservoir drainage.
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Formation Testing: New Methods for Rapid Mobility and Pore Pressure Prediction
More Lessteady-state pressure responses that may require hours of wait time. These imply prohibitive offshore costs and increase the risks of stuck and lost tools; the methods derive from decades-old formulas intended for high-mobility formations which equilibrate rapidly. New math models are introduced that, now assuming high levels of pressure diffusion, require just seconds to yield acceptable pore pressures, and vertical and horizontal permeabilities. These augment traditional methods, providing suites of pressure evaluation tools covering all permeabilities; moreover, they do not require hardware changes to existing tools aside from downhole firmware modifications. For dual-probe tools, we develop analogies to resistivity logging: pump pistons are oscillated sinusoidally, and pressure phase and amplitude changes monitored at observation probes are interpreted using Darcy’s law. Second, parallels to sonic logging are considered: pistons are allowed to impact formations suddenly, and signal arrival times measured at observation probes are converted to mobility. Third, for dual and single-probe systems, rapid “drawdown alone” and “drawdown-buildup” approaches that do not use exponential, transcendental or complicated error functions, but instead, efficient rational polynomial expansions, are described. Detailed examples and validations demonstrate the power and versatility behind the new methods for real-time and job planning applications. Fast calculations support increased downhole data usage, thus enhancing real-time capabilities; they free up resources needed to support other MWD/LWD functions. We also provide a photographic survey of newly developed wireline and “while drilling” formation testers that make use of the fast interpretation models and introduce the reader to new reservoir description capabilities.
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Field Trial Results of a Drilling Advisory System
Authors D.-L. Chang, G.S. Payette, D. Pais, L. Wang, J.R. Bailey and N.D. MitchellField tests of a real-time Drilling Advisory System (DAS) have demonstrated value in several drill well surveillance applications. This system receives drilling data and transmits recommended operating parameters to the driller using existing rig systems and Wellsite Information Transfer Specification (WITS) data records. Using this industry standard, DAS can be deployed to any suitable data acquisition system on the diverse rig equipment available in the industry. The DAS computer may also be connected to a company network to enable desktop viewing of the drilling recommendations in the office. The method embodied in the software comprises both a learning mode and an application mode. In learning mode, systematic changes in parameters are recommended to explore the operating space, and calculation of an objective function determines results. Complex decisions to change operating parameters such as weight on bit, rotary speed, and flow rate can also be made with the assistance of DAS via early detection of drilling dysfunctions which change with depth and formation. The operator’s ROP (Rate of Penetration) management process is focused on MSE (Mechanical Specific Energy) surveillance, and the DAS process extends this methodology to a real-time operating system. DAS is designed to assist the driller by capturing and organizing real-time data without imposing on their judgment and control. It is intended to be a digital helper that enhances the driller’s ability to interpret current drilling conditions and make effective decisions. Remote access capabilities and customized output to the driller’s display were demonstrated in field trials, and key lessons from field trials have been implemented. The field trials included multiple hole sections in onshore and offshore wells across a wide variety of drilling conditions. In one example provided in this paper, the use of DAS provided 35% higher ROP when DAS was used to avoid drilling dysfunctions.
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Characterization of Coalbed Methane Reservoirs: A Unified Geoscience and Engineering Approach
Authors C. Le Turdu, R. Laver and M. Koleylarge volumes of formation water that must be removed before the gas can flow to the surface. This paper describes a new technology- and knowledge-driven approach to address these challenges in the exploration and development stages of a CSG field. During exploration, combining multiple data types in a single model reduces dramatically the uncertainty around coal seam distribution and gas-in-place estimation. In field development planning, the unification integrates static and dynamic data to enable a better understanding of the field’s producibility. The exploitation of CSG requires analyses of many scenarios and uncertainties. In addition, it requires hundreds of wells to be drilled in a short period of time. Consideration of the high levels of uncertainty and the integration of large volumes of newly acquired data can be achieved efficiently only in a unified software environment that is associated with a strong knowledge management system. In fact, one of the key benefits of this new unified approach includes the ability to update models and test multiple scenarios at any stage of the field life cycle, and track the processes with a strong audit trail. Data used for demonstration in this paper are from the Surat basin in Central Queensland, Australia.
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Resolving Eustasy from Neotectonics in the Sea-Level History of the Pliocene to Holocene of Qatar
Authors J. Jameson and C.J. StrohmengerThe evolution of coastal plains, their inhabitation patterns, present day shape, and surface hydrology of Qatar are related to changes in relative sea-level. Several factors, acting on different time scales, have contributed to sea-level changes. These include tectonism, glacio-eustasy and possibly isostatic rebound. The peninsula shape is the surface expression of the Qatar Arch, one of the largest structural features of the Arabian Plate. It plunges northward into the Zagros foredeep. Tertiary age, compressional flexure of the foredeep and plate tilting associated with Red Sea rifting are likely tectonic forces. Previous studies indicate the Arabian Gulf was a fluvial plain during the last glacial maximum 18,000 years before present (yr BP). The Gulf began flooding 14,000 yr BP in response to ice melting. The period between 14,000-9,000 yr BP is marked by a rapid rise (2m/100yr). Age dating of coastal deposits indicates that sea-level was about 2-4 meters higher than present between 8,000-3,000 years BP. Most coastal deposits are relicts of this sea-level highstand. During this period coral reefs formed a discontinuous fringe around the windward and oblique coastlines. A sea-level drop approximately 2,000 yr BP may account for the demise of the fringing reefs. Similar beaches are found elsewhere along the Gulf. The occurrence of Pliocene age fluvial gravel deposits of the Hofuf Formation on hill tops 30 to 90 meters above sea-level are interpreted as related to long term tectonic uplift, associated with the evolution of the Zagros foredeep and structural tilting of the Arabian Plate. Pleistocene shoreline deposits may be part of the same structural flexural event or reflect the marine isotope stage 5e. Data from Pliocene to present suggest that the sea-level history of Qatar reflects relatively high-frequency changes in seal-level driven by eustasy superimposed on a long term pattern of tectonic uplift.
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Production Integrated Smart Completion Benchmark for Field Re-Development
Authors K.S. Chan, R. Masoudi, H. Karkooti, R. Shaedin and M.B. OthmanFor marginal field development and mature field re-development, the main art of maximizing reservoir contact is to design wells that could enable commingle production simultaneously depleting not only the major but also the selected minor sands in the field. Field implementation cases in Malaysia have been shown that this could significantly minimize the well count, increase the well productivity, and improve the ultimate recovery per well particularly in the multiple-stacked and compartmentalized reservoirs. Commingle production from several sands may have the risks and the uncertainties, among others, of layer cross-flow, excessive GOR production and early water breakthrough at certain sand intervals due to uneven pressure depletion, uneven gas and water mobility. These production risks and uncertainties shall be evaluated for ensuring the predicted life-cycle production performance of the designed commingles production wells. Minimization of these risks could involve developing of a pressure drawdown management plan, the optimization of injection fluid conformance control and the prediction of reservoir pressure change. The resulting pressure drawdown plan may then generate a requirement for individual down-hole flow control at each commingled sands. Accordingly, the smart completion comprises of inflow control devices such as passive ICD and/or active ICV with or without down-hole pressure and inflow monitoring devices namely, PDG or DTS installation can then be adequately designed. This paper is to illustrate a production integrated smart well completion design process starting from reservoir drainage and injection points selection, the determination of well reservoir contact trajectory, the production evaluation and risk analysis, and to the selection and application of smart completion devices. The case of a deepwater reservoir field development smart well completion design was used to demonstrate the viability of this integrated engineering approach. This approach is a partial effort to achieve effective field development by lowering the overall field development cost and maximizing the oil and gas recovery. The presented reservoir engineering workflows and completion design methodologies is to constitute a new smart well completion benchmark for well design and production optimization and serve as an engineering guide for optimizing the well construction cost in Malaysia.
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The Awakend Giants
Authors C.S.B. Abdullah and N.F. Bt Mohamad KhazaliSince late 1960’s, there are intensive exploration activities conducted off the coast of the state of Sarawak, Malaysia. The offshore region to the northwest of Borneo Island saw a heightened state of exploration activities for hydrocarbon following increasing demand for fossil fuel as a result of world industrialization. Miocene carbonate pinnacles are one of the target play types identified and chased within the Central Luconia geologic region. In those days the more obvious, mega size shallow carbonate build-ups which are considered as the “low laying fruits” became the first priority exploration test candidates. Some of the pinnacle build-ups are proven gas fields with few of them classified as “giant class” accumulations (Figure 1). Nevertheless, a lower than expected overall exploration success statistical trend coupled with low priority in the business strategy for gaseous hydrocarbon further compounded the issues which arrested the exploration initiatives. A “hiatus” in exploration activities ensued beginning in 1980’s. On the subsurface side, geologic assessments then identified hydraulic seal failure and “thief sand” as the probable contributing factors in the unsuccessful cases. Extremely high aquifer pressure combined with the hydrocarbon buoyancy effects thought to have breached the cap seal mechanical strength which caused capillary hydrocarbon leakages. The presence of post carbonate permeable sandy formation down lapping onto the pinnacle is the other identified geologic risk element. Inter-fingering of the sand and carbonate introduced leak point which provided drainage conduit diverting the hydrocarbon away. The incriminating “blown trap” theory was thence adopted loosely as an explanation to the situation. On the other hand apparent deeply buried pinnacles are intuitively associated with high formation pressure, temperature and non-hydrocarbon gas contaminants further added up the situation complexity. The anticipated drilling operation complications from such conditions are henceforth associated with potential high costs. These conditions summed up have led to premature condemnation of the remaining carbonate pinnacle play type potential in the region. There was absolutely no interest to further realize the hydrocarbon potential of the pinnacles since then. Recent works within the region re-evaluating the similar pinnacles have proved the contrary. The pre-conceived misconceptions of the play types were rectified and adoption of the findings proved very rewarding conclusions.
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Materials and Corrosion in LNG Industry - Our Experiences
Authors J.V.D. Murty and I.A. MuzghiLiquefied Natural Gas (LNG) industry utilizes a variety of materials to serve its needs in diverse service conditions, from cryogenic to moderately high temp applications, to a multiplicity of corrosive environments. The content of the submission is applicable all across the LNG industry. This paper focuses on the applications and materials used by Qatargas for LNG production, at both onshore and offshore facilities. It examines mechanical and metallurgical concerns with emphasis on areas of corrosion and the solutions devised to address these items of interest. The presentation discusses in detail case studies and Qatargas experience in selection of materials, metallurgical problems faced and their failure mechanisms such as graphitization, sigma phase formation etc.; mechanical in nature such as vibration induced fatigue etc.; corrosion in nature such as crevice corrosion, environmental assisted cracking, flow accelerated corrosion, aggressive environmental corrosion etc. and solutions arrived for each of the cases. These case studies will be supported by data, analysis, with photographs and other relevant facts and figures for reference as well as details of solutions and remedial measures implemented for each of the cases. As subject matter of the presentation presents case studies of problems faced and solutions reached, the information will be directly applicable to similar service conditions and will be of direct significance to LNG industry.
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An Experimental Investigation on Archie Parameters at Ambient and Overburden Condition of Iranian Clean Carbonate Reservoir Rock and Developing a new Formation Resistivity Model for Limestone and Dolomite Samples
Authors E. Eshraghi and J. MoghadasiElectrical resistivity measurement is widely used to estimate porosity and water saturation. Archie equation is not easy to ap-ply to carbonate rocks because formation parameters (a, m, n) are functions of changes in the pore geometry, clay content, tortuosity of the pores, as well as formation pressure. The Archie equation is also valid only when the rock is strongly water wet and clay free, which is not the case in carbonate rocks, Therefore cannot be generalized over the entire carbonate reservoir, so the straightforward application of that in carbonate rocks has severe limitations. In this paper, we discuss a new method using saturation analysis data to derive the correct form of the Archie Equation that can be applied to carbonate rocks. Correlations among resistivity, and porosity derived from 108 actual core data of 18 core sam-ples (10 dolomite and 8 limestone samples) in 6 different overburden pressures. The generalized equations can then be applied to any carbonate formation with varied geometry and clay content. The results of this comparison showed that the new developed model gave the best accuracy with average absolute errors of 20.4% and 10.9 % for dolomite and limestone samples respectively, while the other common models are ranked, according to their accuracy in the following order to be Humble, Archie, and Shell, with average absolute errors of 26.0 %, 26.7 %, and 32.6 % respectively for dolomite samples and in order to be Archie, Humble, and Shell with average absolute errors of 12.2 %, 22.3 %, and 26.2 % respectively for limestone samples. The advantages of this model is Improving the accuracy of formation resistivity calculations by exerting the overburden pressure effect and specially usage of each formula for each mineral type.
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3D OBC Seismic Survey Productivity Enhancement with Satisfying Geophysical Requirements
Authors S. Nakayama and K. BelaidOcean Bottom Cable (OBC) seismic survey has several technical advantages over conventional towed-streamer technique as it enables the acquisition of wide azimuth and high fold datasets having long offsets and less spatial discontinuities. However, its usage is still limited because of requirement of relatively large operational efforts which likely results in more survey cost and duration. Consequently, optimization of OBC seismic survey productivity is essential to narrow the business gap with towed-streamer acquisition and enhance widespread applicability of OBC techniques. Due to the decoupled aspect of the source and receiver lines, OBC survey can inherently form numerous survey designs. Our study is conducted with the aim to find efficient OBC seismic survey designs that still satisfy established geophysical objectives among infinite selections. We introduce survey designing criteria on the basis of sampling of OVTs (Offset Vector Tile) which allows us to achieve desired offset and azimuth distributions in final imaging. Productivity analysis is then performed based on current equipment availability enabling a variety of survey designs and geometries which were not feasible previously. We also adapt several geometry options including two dual source-vessel operations: (1) Distanced Separated Simultaneous Shooting (DS3); and (2) Dual Source-Vessel Flip-Flop Shooting (DSVFFS). Applicability of dual source-vessel operations to OBC survey has not been well described unlike marine towed-streamer and land cases. Thus, we analyse the impact of dual source-vessel operations on OBC survey efficiency. Additionally, we discuss technical challenges resulting from the relationship between OBC survey designs and the resultant interference noise wave fields not generally associated with other acquisition techniques.
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Development of a Polymer Gel System for Improved Sweep Efficiency and Injection Profile Modification of IOR/EOR Treatments
Authors F. Crespo, B.R. Reddy, L. Eoff, C. Lewis and and N. PascarellaThe existence of high-permeability features, such as fissures, fractures, and eroded-out zones, diminishes the sweep efficiency of any water, gas, or polymer flooding operation. Placing crosslinked conformance polymer gels or other types of blocking agents in injection and/or production wells can generate the necessary flow diversion for increasing the recovery factor of enhanced oil recovery/improved oil recovery (EOR/IOR) treatments. This paper evaluates a high-molecular-weight (HMW) organically crosslinked polymer (OCP) (referred to as HMW-OCP) gel system for such scenarios. This conformance technology is the result of crosslinking reactions between HMW polyacrylamide and polyethylenimine (PEI). The relatively medium viscosities of the fluids caused by the HMW of the components of the system allows for in-depth gel placement in fractures and high-perm channels, without invading the matrix of the rock. A low-molecular version of this polymer system has proven to successfully control water production in matrix applications. This HMW-OCP system gelation occurs gradually with time and temperature and can be designed to suit the need for short and long placement times. Optimization of gelation times using chemical activators and bimodal distribution of polymer molecular weights (MWs) is discussed. Fast hydration of the base polymer provides on-the-fly mixing capabilities. Also, the use of all liquid polymers and additives allows ease of transportation, handling, and storage and mixing of large volumes of material usually necessary for this type of treatment. Laboratory test results show long-term plugging capabilities, thermal stability, and fluid-loss control.
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Compromise: An Innovative Method for Combining Proportion Cubes for Facies Modeling
Authors E. Tawilé, S.-B. Ahn and P. SchirmerCompromise is a methodology that is based on an iterative solver that allows combining multiple proportion cubes given that a priori reference proportions are provided within a defined facies simulation perimeter. The novelty of the methodology is the possibility to choose the amount of imprint of a given trend while respecting quantitative proportion constraints. It has been successfully tested on several operational studies and is now used in a routine basis whenever having multiple facies trends to manage. For each study, the proportion cubes were provided by different sources; the methodology is source independent as long as it is expressed as a proportion cube. Seismic, concept and well data are possible sources of proportion cubes. It is tool-independent and is implemented today as workflows and scripts. It is also planned to be developed as an independent module on for increased user-friendliness.
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Artificial Lift Performance Enhancements by applying Root Cause Failure Analysis
Authors S.G. Lapi, M.E. Johnson and B. ArismanThis paper describes the use of a Root Cause Failure Analysis (RCFA) process to improve artificial lift systems performance: Electric Submersible Pumps (ESP) and Progressing Cavity Pumps (PCP). The subject field is remote and heavy oil environment with a wide range of production rates, fluid types, and reservoir conditions. Conditions are challenging for ESPs including severe emulsions at high water cuts, and the conditions are challenging for PCPs with relatively deep pump landing depths and high water cut. The field contains more than 800 active wells with continuous drilling operations. Pump repairs are a major part of workover rig activity. Early in the life of the field, failure rates were rapidly increasing. Collaborative efforts were established among the vendor and functional teams to address failures. The RCFA process was established with the objective to evaluate every failed pump system to determine the reason for failure, identify contributing factors, and monitor trends. The RCFA process evaluates pump performance, well test history, well intervention history, and artificial lift designs. Another key aspect of the RCFA review process is to evaluate compiled equipment teardown information. The RCFA meetings are used to share information and insure open communication among the parties. The meetings are also used to identify additional data requirements to help determine a root cause of failure. The RCFA process has led to revised equipment design and selection criteria, helped to develop new surveillance tools and processes, enabled optimized operational envelopes, and improved installation procedures. These processes and tools can be transferred and implemented successfully for other projects to help maximize value of the asset. The RCFA process was fully implemented and consistently applied since 2006 and has helped to reduce the failure frequency more than 70 % on ESPs and more than 50 % on PCPs, despite the fact that ESP population has more than tripled and PCP installations has more than doubled.
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Well Services Operations in Offshore Unmanned Platform; Challenges and Solutions
Authors O. Alyafei and J. Fosterpact from the three factors are presented. Various strategies were employed to mitigate negative impact on campaign safety, cost, and schedule. Some challenges include how to address personnel accommodation and equipment limitations (number, size, and weight) through the use of supply vessels, DPI/DPII intervention vessels, jack-up rig, fast crew transfer, barge, and Liftboat. Another area that required numerous remedial measures was safety systems, e.g. fire water/deluge systems. Other conditions that affect performance are the reservoir’s relatively shallow nature and down-hole conditions that require special rig-up. Along with scope of work challenges, weather is a major consideration when determining the intervention strategy for unmanned platforms. Determining how to limit standby time, overcome personnel and equipment limitations, and continue to work safely is the greatest challenge of all. All of these requirements formulate part of the criteria in selecting an intervention vessel/rig/Liftboat which directly impacts schedule and cost. The major challenges over the past few years will be discussed, including their effectiveness, efficiency, and specification. Furthermore, a summary of how the challenges were overcome based on safety, uptime, and personnel accommodation is given.
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Qatargas Greenhouse Gas Management Strategy
Authors K.A. Al-Sulaiti and A.A. SubedarClimate change presents a fundamental challenge to the way industries use energy and resources. Qatargas, the world’s largest LNG producer is improving operational performance and energy efficiency to reduce Greenhouse Gas (GHG) emissions through an effective, well-structured and maturing GHG management strategy. This approach is aligned with the State of Qatar’s position on climate change. Qatargas’ strategy has three phases. Phase 1 involved understanding the GHG issue, preparing an action plan, and focusing on internal capacity building through analysis of GHG policies, projects and markets. It also analyzed the potential impact of climate change on Qatargas’ operations, and reviewed potential opportunities to reduce GHG emissions and participate in the global carbon market. Phase 2 of the GHG strategy focuses on: • Preparing a comprehensive GHG emissions inventory that includes emission sources from various business divisions, development of GHG management procedures and plans, and corporate GHG KPIs; • Benchmarking GHG efficiency per tonne of LNG produced; and • Comparing company GHG performance relative to peer companies. Qatargas’ verified emissions inventory portfolio is providing data and trends, which is assisting in the understanding of key emission sources and provides a platform to progress Phase 3 of the GHG strategy. Phase 3 focuses on carbon reduction opportunities and abatement techniques via sustainability assessments and engineering studies; and will also include a Life Cycle Assessment for GHG emissions from Qatargas’ operations. These are in addition to the ongoing emissions reduction efforts such as the Flare Management Team initiative and the upcoming Jetty Boil-off Gas Recovery (JBOG) project.
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Qatar LNG Terminal Flare Gas Reduction Project – JBOG
By B. MirzaQatar produces 77 million tonnes of LNG per annum, and is the largest provider of this clean energy in the world. The world’s largest man made harbor in Ras Laffan City, located 80km north of Doha, has six LNG loading berths. During loading of the liquefied natural gas in the special LNG ships, a portion of the minus 160oC liquid boils off as it comes in contact with the warmer ship tank. This boiled off gas is currently being flared at the berth because there is no outlet for this low pressure gas. The average flow rate of the boil-off gas is 100 mmscfd, which has the potential to produce around 750MW of power. In line with Qatar’s National Vision to produce and supply clean energy to the world, Qatar Petroleum and the Ministry of Environment decided to recover the flared gas at the LNG berths to the maximum extent practical. This intent gave birth to the Jetty Boil-off Gas Recovery Project in 2007. A Pre-FEED design had been done by RasGas, and the project was handed over to Qatargas in June 2007. The JBOG Project when fully implemented will save the emission of 1.6 million tonnes of carbon dioxide into the atmosphere. One trillion cubic feet of gas will be saved for the State of Qatar over a period of 30 years.
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Quantitative Formation Evaluation in High Angle and Horizontal Wells - A Step Change in Reservoir Characterization
Authors J. Zhou, P. Guo, A. Mendoza, Q. Passey, S. Wertanen and P. GaillotAdvanced directional drilling technology has made it possible to drill extended reach wells with long horizontal displacements, resulting in optimally placed wellbores within reservoirs and more economical hydrocarbon production. Logging-while-drilling (LWD) technologies provide new opportunities to improve reservoir characterization and geologic models however, the complicated wellbore and formation geometries in highly deviated wells impose difficulties for quantitative interpretation of well logs using conventional petrophysical analysis methods. LWD log interpretation in high-angle and horizontal wells is often limited to geosteering in well placement applications and qualitative reservoir description. We developed a state-of-the-art formation evaluation toolkit for quantitative interpretation of well logs in high-angle and horizontal (HA/HZ) wells. Starting with wellbore images and standard triple-combo field logs, the workflow consists of: 1) 3D and 2D displays for well path, wellbore images and field logs to quality control the data; 2) comprehensive image and log analysis to build a 3D geometrical earth model; 3) depth coherence analysis to effectively correct the recorded wellbore images of various logging tool sensors with different depths of investigation; 4) 3D joint inversion to accurately model and interpret gamma-ray, neutron, density and resistivity logs in order to build a common petrophysical earth model; and 5) populating the common earth model with bedding geometries and rock- and fluid-property distributions. The toolkit has been successfully applied to a field example to illustrate its applications in quantitative reservoir characterization of net-to-gross (N/G), porosity (), and water saturation (Sw). Incorporating more accurate descriptions of bedding dips and azimuths from HA/HZ wells within the earth model results in improved geologic models for reservoir simulation. Sensitivity analysis in the workflow defines the uncertainties in wellbore image analysis and wellbore directional surveys. Additional uplift in reservoir characterization includes quantifying lateral variations and improving reservoir facies classifications, along with delineating potential calcite zones and quantifying stratigraphic bedding and orientation. The results include bed thickness distributions and guidance to appropriate petrophysical cutoff values.
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Shale-Fluid Interactions and Drilling Fluid Designs
Authors W. He, S.L. Gomez, R.S. Leonard and D.T. LiDrilling of shale has long been a challenge due to the strong sensitivity of shale to drilling fluids. Improper selection of drilling fluid may cause strong shale-fluid interaction and, consequently, wellbore instability. It is critical to design drilling fluids so as to minimize the shale-fluid interaction. Shale can possess different behaviors when in contact with fluid (e.g., fracturing, swelling, and dispersion). The differences in shale-fluid interaction are mainly related to its clay minerals, structure, bedding and thin laminae, and pre-existing fractures. The rate and strength of interaction vary for different shales. While strong fracturing or dispersion could happen in just a few minutes for some shales, other shales exhibit only very weak fracturing after days in contact with the same fluid. Confining pressure can significantly reduce the propagation of fractures, but pre-existing fractures can be enlarged or extended due to fluid invasion. Due to the variations of shale and the resulting differences in shale-fluid interactions, the shale behavior of fluid in one area or formation cannot always be extrapolated to another area or formation. For a specific shale formation, the understanding of diagenesis, bedding and thin laminae, pre-existing fractures, and abundance and distribution of reactive clays such as smectite, helps predict the potential shale instability. For example, if shale with high smectite content has not experienced substantial compaction and thermal alteration, it may show a strong tendency for dispersion. Alternatively, if high-smectite shale has experienced strong compaction and thermal alteration and shows laminated structures, fracturing along bedding planes or laminae could be the dominant deformation mechanism in fluids. Our laboratory tests indicate that even for highly reactive shale, proper inhibition can be achieved if the composition and concentration of chemical additives in drilling fluids are selected appropriately.
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Waterflood Performance Monitoring of Fluvial Reservoir through Saturation Logging – A Case Study of Mangala field
Authors D. Prasad, S. Verma, P. Kumar, A.K. Singh, R. Tandon, V. Ravichandran, P. Shankar and P. SinghThis paper discusses the application of saturation logging to characterize the water flood performance, sweep, importance of vertical conformance in moderately varying to high net to gross fluvial system, at one of the largest onshore field Mangala in Barmer basin, India containing ~1.3 billion initial oil in-place. Mangala field was discovered in 2004 and was brought on production with hot water flooding in August 2009. Structurally Mangala is a tilted fault block consisting main oil bearing reservoirs of Fatehgarh group of Cretaceous/ Paleocene age as the main sandstone reservoir unit (~250 meters) dipping at around 9 degrees to the east. The Fatehgarh group is subdivided into 5 major reservoir layers litho-stratigraphically termed FM1 (top) to FM5 (base). The lower Fathegarh Formations (FM3 to FM5) are dominated by well-connected sheet flood and braided channel sands having net to gross ~ 80%, whilst the Upper Fathegarh Formation (FM1 and FM2) is dominated by more sinuous, laterally migrating fluvial channel sands transitioning into lacustrine depositional system at the top and having net to gross <50%. The reservoir in general is of high quality with multi-darcy permeability, porosity > 25%; with relatively viscous (15cp) and waxy crude. The FM1 and FM2 are developed with downdip edge line drive and inverted 9- spot pattern. The massive FM3 and FM4 sands have been developed with a downdip edge line drive and up-dip horizontal producers. Saturation logging with Production logging is very important tool in monitoring the field injection performance. Time lapsed saturation logging data suggested that the FM-3 is sweeping very nicely from the bottom whereas in FM-4, the intra-shale layers are extended and thus not allowing the bottom sweep in some area. The FM-1 has come up with the conformance issues which suggest that the injection is not getting uniformly distributed across layers, resulting in the non-uniform sweep. Saturation log has helped in monitoring varying sweep in different reservoir units, sand to sand correlation in highly heterogeneous FM1 reservoir unit with the integration of Production Logging and other data in Mangala field. The improved understanding of conformance, production and injection has helped in locating the un-swept areas targeted for selective injection and drilling infill wells.
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Reservoir Simulation Modeling of the World's Largest Clastic Oil Field - The Greater Burgan Field, Kuwait
Authors E. Ma, S. Ryzhov, S. Gheorghiu, O. Hegazy, M. Banagale, M. Ibrahim, O. Gurpinar, L. Dashti, J.-M. Filak, R. Al-Houti, F. Ali and J. Al-HumoudThe Greater Burgan field in Kuwait is the largest clastic oil field in the world. Its sheer size, complex geology, intricate surface facility network, over 2,200 well completions and 65-years of production history associated with uncertainty present formidable challenges in reservoir simulation. In the last two decades, many flow simulation models, part-field and full-field, were developed as reservoir management tools to study depletion plan strategies and reservoir recovery options. The new 2011 Burgan reservoir simulation effort was not just another simulation project. Indeed, it was a major undertaking in terms of technical and human resource. The model size, innovative technology, supporting resources, integrated workflows and meticulous planning applied to this project were unprecedented in the history of the Greater Burgan field development. The quest began in 2009 with the construction of a Structural and Stratigraphic model, followed by Static modeling in 2010 and Dynamic modeling in 2011. Early dynamic model startup allowed integration between the static and dynamic modeling teams which resulted in a geological model suitable for reservoir simulation. This paper describes work done to prepare a representative numerical model which could be utilized to optimize the remaining life of the reservoir complex. Right from the onset, representative numerical modeling concerns were identified. These led to a systematic collaboration framework being built in place between the static and dynamic modeling teams. Calibration of the model to the historical observations was executed at three levels, Global, Regional and Wells – the Cascade Approach. The cascade approach was designed to enable a concerted model calibration effort in accordance with the recurrent data quality. For instance, while the total field production history attains a high degree of accuracy, the data at the regional Gathering Center (GC) is of a lower level of certainty, but far more reliable than the data at an individual well. Commercial modeling software have been utilized extensively to produce several utilities such as water encroachment maps, Repeat Formation Tester (RFT) matching tools and aquifer definition and adjustment workflows. Subsequently, synergy in the integrated use of these tools produced a robust model calibration process on all three levels in the cascade approach. The second part of the project was to develop a predictive simulation model to be used as a reservoir management tool to forecast and evaluate reservoir development options for ultimate recovery. Check-point prediction models were defined and constructed at regular intervals during the model calibration phase. This approach allowed qualitative assessment on the evolution towards a representative numerical model. Furthermore, it allowed synchronizing simulation workflows and expedited project deliverables. The overall result was a sound full-field reservoir simulation model that achieved a good match of production, pressure and saturation histories, leading to reliable forecasting of oil recovery under different development scenarios.
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Lower Jurassic Source Rock Contribution on Cretaceous and Tertiary Reservoirs Hydrocarbon Filling of Oil Fields, North West Persian Gulf, Iran
Authors P. Hassanzadeh and M. KhaleghiIn the first comprehensive study of the Northwest margin of Persian Gulf basin petroleum system of offshore Southwest Iran, we test oil–source rock correlation through molecular biomarker and Carbon Isotope analysis of oil samples from wells scattered throughout the region, as well as purported source rocks. The chemical compositions of 11 crude oils and 9 extracts of potential source rocks from the Bahregansar-Hendijan High and two adjacent fields of the North West Persian Gulf sedimentary Basin, Iran were studied in detail by geochemical methods in order to understand their genetic relationship. The oil samples were collected from the all producing fields. The rock samples studies, selected after Rock-Eval pyrolysis screening of a large suite of samples, consist of 32 shale samples distributing from Lower Cretaceous up to Lower Tertiary in the stratigraphic column of the studied oilfield. The new data presented in this manuscript suggest that the oils constitute two oil families, and that the source rock was predominant marine shale deposited in an oxic to suboxic environment. Possible source rocks were selected and analyzed from different wells and compared with the oils. A negative correlation suggests that Upper Cretaceous intervals of limestone, marl, and black shale previously believed to be important source rocks can be discounted as an important contributor to Northwest Persian Gulf basin oils. Instead, the new data suggest a Lower Jurassic source rock contribution in charging Cretaceous and Tertiary reservoirs of Soroush, Abouzar, Nowroz and Arash oil fields.
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Qualification of an Innovative Sealant to Ensure Hydraulic Isolation in TTRD Application in the Presence of a Downhole Pressure and Temperature Gauge Cable
By J. BedelIn a mature field, where the strategy for accessing the remaining reserves is driven predominantly by cost reduction, through-tubing rotary drilling (TTRD) can provide the optimal solution. TTRD allows for low-cost sidetracking opportunities to near-wellbore targets by leaving the existing completion and Christmas tree in place. Additional time and cost savings are achieved once the well has been drilled as there is no need to run a new completion. In a project in the North Sea, the casing design requires that the TTRD candidate wells have a dual-casing exit above the production packer to access the location of the proposed hydrocarbon target. This operation requires a cement plug to be circulated into the annulus between the 5.5 × 7-in. tubing and the 9 ⅝-in. casing. The purpose of this specific cement plug is to provide tubing stability during the window milling operation and annulus integrity for the lifecycle of the new TTRD well. It will then act as a production packer, and it will also serve as the first abandonment plug for the donor well. Finally, the top of cement of the annulus cement plug should also leave enough space below the 9 ⅝-in. casing to allow for the final abandonment. The main complication with this cementing operation is caused by a downhole pressure and temperature gauge cable that runs from below the proposed kickoff point up to the tubing hanger. The risk is that this cable could potentially cause micro-annuli within the annulus cement plug and hence impair the integrity of the well. A further potential issue can arise if the gauge cable is sheared during the window milling operation, thus creating the potential for hydrocarbons to travel up through its core to the tubing hanger. A cementing service company designed and qualified an innovative sealant that can be used to meet the above criteria. Large-scale laboratory testing was undertaken to meet the technical and operational acceptance criteria.
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New Insights into Low Salinity Water Injection Effect on Oil Recovery from Carbonate Reservoirs
Authors E.W. Al-Shalabi, K. Sepehrnoori and M. DelshadLow salinity water injection (LSWI) is gaining popularity as an improved oil recovery technique on account of being cost effective compared to other water based enhanced oil recovery methods such as chemical and steam flooding. In this paper, the wettability alteration option in our in-house simulator is used to history match and provide some insights in different seawater dilution cycles based on recently published corefloods. Two newly proposed methodologies to model dilution cycles are employed. We successfully modeled the experiments enhancing the wettability alteration model in the simulator using two different scaling factors. The study also revealed that the process is more sensitive to oil relative permeability compared to that of the water phase. A linear interpolation model for residual oil saturation (Sor) was proposed.
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How to Find Low Resistivity Pay in a Mature Oil Field K- Field Case Study
Authors S.M. Poerboyo and K.R. SuharyaPrior to 2010, all oil from the K field was produced from the Lower Sihapas Formation, where oil could easily be identified from electrical logs in these thick, high-quality sands. Then, in 2010, something unusual happened. When drilling an infill well, we noticed good oil indications from mud logs in sands above the Lower Sihapas Formation, despite the low resistivity less than 4 ohm-m. We completed the sand and it flowed 146 BOPD with zero water. This unexpected result prompted us to conduct a short two-week study to identify other candidate wells. The study consisted of: collection of mud and wireline log data in all K wells; re-running petrophysical analysis using new a, m and n values for low resistivity sands; and ranking candidate wells based on sand quality, gas readings, oil shows, initial oil rate prediction, well cost and the chance of making money. The study identified 17 candidate wells to re-complete in the Upper Sihapas. To date, we have worked over seven wells with an oil gain of 700 BOPD and estimated incremental oil recovery of 175 million stock tank barrels. One of the worked-over wells, the one with the lowest EMV, flowed water. This paper describes the study, the resultant workover campaign and lessons learned.
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Calibrating Log Derived Stress Profiles in Anisotropic Shale Gas Formations- Incorporating Lab and Field's Measurements for Localized Model
Authors A. Almarzooq, H. Aljeshi and A. AlAkeelyThe complex properties of the unconventional gas resources pose challenges to petrophysical evaluation techniques and tools. Data from standard logging tools and standard interpretation techniques produce high levels of uncertainties in the analysis, hence, limiting their reliability in producing thorough petrophysical solutions. Both tight and shale gas formations add multiple layers of complexity to the petrophysical evaluation with complex lithology and heterogeneity causing uncertainty in the hydrocarbon volume calculations and hydraulic fracturing completion designs. Without an accurate completions design, it would not be possible to produce at an economic rate or volume from these formations. Therefore, the need for accurate petrophysical and Geomechanical properties is critical for shale gas formations development. This paper provides field examples with workflow for identifying the anisotropy, calculating the log derived stress profiles and demonstrating the use of lab and field data for calibrating the log measurement. The lab measurements include the elastic moduli conversion dynamic (from logs) to static (from laboratory), stiffness tensors utilizing the oriented velocities in addition to rock strength and related parameters. This part includes the use of oriented velocities from the lab to validate and correct the existing tensors' correlations (Annie). Correcting the logging tool's measurement for factors such as the gas content and the acoustic conversion models will also be illustrated. The field data include the integration of the pre-fracturing job or mini fracturing to calibrate the calculated minimum horizontal stress (closure pressure) and post fracture analysis to validate the models. The result of these calibrations is a more accurate estimation of the formation stress profiles which improves the completion designs. Once these calibrations are done correctly, more accurate stress profile can be calculated in offset areas where cores or mini-fracturing measurements are unavailable. This paper shows the process for calibrating the log derived stress profile and goes through the components and uncertainty.
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The Controlled Freeze Zone Technology for the Commercialization of Sour Gas Resources
Authors J.A. Valencia, S.D. Kelman, A.K. Nagavarapu and D.W. MaherControlled Freeze Zone™ is an efficient single-step cryogenic distillation process for the removal of carbon dioxide, hydrogen sulfide and other impurities from natural gas. Rather than avoiding the freezing of CO2 at cryogenic temperatures, the solidification is allowed to take place, albeit in a very controlled fashion. The technology has shown the potential to more efficiently and cost-effectively separate carbon dioxide and other impurities from natural gas, and to discharge these contaminants as a high-pressure liquid stream ready for underground injection, either for enhanced oil recovery applications or for acid gas injection disposal.
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The Hydrocarbon Pipeline Network and Development in Qatar
More LessThe Transmission and Distribution Network comprises of interconnected gas and oil pipelines network of approximately 3000 km length, associated manifolds and more than 70 distribution stations located through Qatar. The hydrocarbons transported in this network such as sweet Methane gas, Ethane network, stripped associated gases, and tail gas, etc… are all utilized as fuel and feedstock gases to supply the various power plants and industries located in the State of Qatar. In addition, Transmission and distribution network is also responsible to monitor and maintain all QP and third party Companies’ pipelines such as row gas, condensate and LPG pipelines, Ethylene pipeline and crude oil pipelines. As the State of Qatar is booming with tremendous expansion and development to the infrastructure for hosting the FIFA World cup 2022 and to meet its 2030 National Vision, the Gas pipeline network is also being expanded to meet Year 2030 supply and demand forecast, future industries and Urban and infrastructure development. The aim of this paper is to illustrate the development/expansion of QP pipelines network to cover the future national gas supply and demand forecast up to 2030. This will cover the expansion of power generation due to the increase in future national energy demand and the expansion and requirement for the new industries. In addition, the paper will highlight the urban development requirement such as domestic gas supply to houses and using Compressed Natural Gas CNG for local transportation. Moreover, the paper will discuss the infrastructure developments such as the new pipeline corridor tidiness and rationalization, new rail way interfaces with the existing pipeline network, and new Jet fuel requirement to the new Doha International Airport. All the significant challenges and lessons learnt for the network’s planning, interfaces, construction, re-routing and operational challenges will be also addressed in this paper.
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IPM Tool for Strategic Decisions: Diverse Applications of IPM in the Supergiant Tengiz Field
Authors S. Kabdenov, M. Aitkazin, S. Macary and A. AitzhanovIntegrated Production Modeling (IPM) is probably the most popular suite of software for production optimization and planning. It affords the opportunity to model the entire production system from the reservoir through the surface gathering system to the process facilities. This paper describes applications of IPM to the various strategic decisions made in Tengizchevroil LLP (TCO). Within TCO, a full field IPM model is used for an integrated production capacity management plan considering three time periods: short, mid and long-term. Each model has its own strategic focus and is owned by a specific team, all working together in close communication. The short-term model is used to investigate the impact of field operations and surveillance on field production capacity so that all processing facilities are kept full. The mid-term model is used for debottlenecking and gathering system optimization, understanding new drilling hook-ups, and impact of workovers on system capacity. This model uses a time window of up to five years and is also used for Business Plan support. The long-term model, which is the core of this paper, focuses on major capital projects and is typically run for decades. The main objective of long-term IPM modeling is to run production forecasts while honoring surface constraints; keeping the existing and future processing facilities full is the desired outcome. The long-term model handles not only the oil system, but also sour gas injection and waste water disposal. It models all current gathering systems, with whatever modifications or short-term projects adopted by the mid-term model inclusive and future growth plans. Examples, lessons learned, and challenges of strategic decisions made by using IPM will be shown and discussed in this paper. This includes well count study, pipeline sizing, meter station assignment, timing of rigs and projects, and drilling schedule. One of the main lessons learned was the importance of cooperation with the reservoir simulation team in unifying constraints, incorporating the impact of reservoir uncertainty on production profiles, and developing mitigation strategies for unfavorable outcomes. Other value is derived from coordinating base business IPM results with those of the design team that handles future growth projects.
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Advanced Reservoir Characterization for CO2 Storage
Authors A. Al-Menhali, C. Reynolds, P. Lai, B. Niu, N. Nicholls, J. Crawshaw and S. KrevorInjection of CO2 into the subsurface is of interest for CO2 storage and enhanced oil recovery (EOR). There are, however, major unresolved questions around the multiphase flow physics and reactive processes that will take place after CO2 is injected, particularly in carbonate rock reservoirs. For example, the wetting properties of CO2-brine-rock systems will impact the efficiency of EOR operations and CO2 storage but reported contact angles range widely from strongly water-wet to intermediate wet. Similar uncertainties exist for properties including the relative permeability and the impact of chemical reaction on flow. In this presentation we present initial results from laboratory studies investigating the physics of multiphase flow and reactive transport for CO2-brine systems. We use traditional and novel core flooding techniques and x-ray imaging to resolve uncertainties around the CO2-brine contact angle, relative permeability, residual trapping, and feedbacks between chemical reaction and flow in carbonate rocks.
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Successful Application of Compact Low Pressure System in CC Field, an Optimized Version for Smaller Surface Deck Platforms
Authors Z.M. Mainuri, M.H. Mohamad, D. Gajet and P.K. HoongOptimization of mature fields in maximizing the hydrocarbon recovery has been a major concern for exploration and production companies including PETRONAS Carigali Sdn. Bhd (PCSB). CC is a brown field, situated in south central region of the DD Province of the Sarawak Basin.Since CC field has marginal reserves, an effort to enhance the production was initiated with the objective of economically boosting the remaining reserves.The proven Low Pressure System (LPS) that is widely implemented across Petronas operating fields has benefited CC in optimizing the production by lowering the existing surface back pressure. However, the challenges faced in implementing the system in CC are platform surface constraintand unmanned-operation-at-night philosophy. Through further optimization on the existing LPS design and the estimated production from LPS well candidates, Compact Low Pressure System (CLPS) was born. The smaller package is lighter compared to existing system and has more flexibility and mobility. The separator process can cater up to 4000 bopd with approximately 4.0 MMscf/d of gas disengagement. This package consists of three major equipments compacted in one skid, which are shut down valve (SDV) for emergency purposes, vertical separator (V-100) for liquid storage and flow rate measurement, and transfer pump for pumping back the liquid to the main production line. The total dry weight of this skid is approximately 9.8 tonnes with smaller foot print of 8.3 m2. Preliminary well candidates were chosen mainly based on well status (idle well/string were given higher priority), water cut and sand control equipment in place. Then, a network model was generated using Integrated Production Modeling (IPM) software to simulate several operating scenarios and choose the best candidates. To-date, the additional oil gained from the selected 5 wells is approximately 400-600 bopd. With this achievement, CLPS has shown the capability of improving the production by overcoming the surface back pressure impact and solving space constraint issues for wells located in small wellhead platforms.
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RasGas Experience with Production Optimisation System, a Success Story
Authors Sabry A. Mohammed, Mokhtar Berzou, L.B. Morshidi and Hani Al-Kharazl-time database for real-time monitoring and system updates. The PROMPT system is model centric and relies on rigorous physics, while its strength relies on using multiple seamless automatic and manual workflows. Many key calculations take place automatically and continuously however, other central workflows rely on engineering judgment such as well models updates. The PROMPT system has successfully demonstrated its reliability in supporting RasGas efforts to achieve long term production deliverability and secure RasGas’ contractual Liquefied Natural Gas (LNG) demand by meeting the LNG production targets and maximising recovery. This is attained by producing the field/wells per the optimum depletion strategy while honoring facility constraints, system availability (well/platforms/pipeline, planned and unplanned downtime, etc.) and operational limits. RasGas uses the PROMPT system to generate well production guidelines as per the optimum reservoir depletion strategy to meet short term production targets. The PROMPT platform is equipped with an optimizer “Excel Solver” where the desired depletion strategy is coded and implemented. This depletion strategy is translated to actuality by generating short-term production guidelines on a regular basis while honoring the production system constraints. PROMPT is effectively used for real time monitoring and compliance with production guidelines, such as monitoring deviations of daily production from pre-defined targets, and for making well rate adjustments during planned/unplanned shutdowns or increased demand. It gives the engineers the ability to test different well operating strategies in off-line simulation to fine-tune production guidelines to meet changing field conditions and enables effective data integration between RasGas engineers in the Sub-surface group with those in the Operations groups.
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Carbonate Reservoir Analogues and Clumped Isotopes: How Combined Geometries and Geochemistry of Outcrops Help Reservoir Management in the Middle East
Authors C. M. John, V. Vandeginste, A.-L. Jourdan, T. M. Kluge, S. Davis, C. Sena, M. Hönig and J. BeckertPetroleum geologists working in carbonate plays are facing two common and inter-connected challenges linked to optimizing production. First, constraining the geometry, spatial distribution and inter-connectivity of reservoir geobodies is crucial as these properties can control the permeability anisotropy of reservoirs zones. This is difficult to do at the inter-well scale due to the limited resolution of seismic methods (20 meters or higher) compared to the size of typical reservoir geobodies (tens of centimers to meters and higher) and the very heterogeneous nature of carbonate reservoirs. Furthermore, diagenetic transformations are very important in carbonate reservoirs. Being able to fingerprint the process and timing of diagenetic transformation is crucial to a correct assessement of the distribution of cemented zones in the subsurface. The issue of diagenesis is also important for organic matter maturation and the timing of oil migration, and therefore the second challenge faced by reservoir geologists in carbonate plays is one of constraining as well as possible the thermal history of the targeted basin. This paper reports on the results of a major long-term research effort that addresses some aspects of this double challenge in the Middle East, and that focused on novel isotopic methods to constrain the thermal history of carbonate phases in the context of the geometry of geobodies measured at the outcrop. Geological work under the Qatar Carbonates and Carbon Storage Centre (QCCSRC), funded jointly by Qatar Petroleum, Shell and the Qatar Science & Technology Park, has as its long-term research goals to improve characterization of subsurface anisotropies in carbonate reservoirs, notably for CCS operations.
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High GOR ESP Experience and Development Concept for a Challenging Oil Field in the Sultanate of Oman
Authors M. De Berredo, I. Sipra, H. Al Muqbali, A. Al-Bimani and G.H. Lanierg’s to date, the study provided the technical basis to assure feasibility of the proposed development plan for the expected high GOR producing environment. Further economic assessment of the artificial-lift selection decision, which is not detailed in this paper, supported a significant impact to the project on the order of 1/3 of its expected value. This paper summarizes the range of PDO operating experience to date with ESPs installed in high GOR conditions. Additional details are shared regarding the feasibility study for field T including supporting rational for the artificial-lift selection for the project concept selection, proposed well completion concept design and the artificial-lift economic evaluation. Finally, established best practices for high GOR fields and key challenges going forward will be discussed.
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Modeling and Analysis of Axial and Torsional Vibrations of Drillstrings with Drag Bits
Authors J.M. Kamel and A. YigitRotary oil-well drilling systems supplied with drag bits are used to drill deep boreholes for the exploration and the production of oil and natural gas. Drilling systems usually suffer from severe vibrations, which occur as axial, lateral and torsional oscillations. These vibrations mostly cause failures of drill-strings, abrasive wear of tubulars, damage of the bit, reduction of the rate of penetration (ROP), and incur high costs. Despite extensive research in this area, there is still a need to develop a consistent model that adequately captures all relevant phenomena such as nonlinear cutting and friction forces at the bit/formation interface, drive system characteristics and coupling between various models of vibrations. This study presents a physically consistent nonlinear lumped-parameter model for the coupled axial and torsional motions of a rotating drill string equipped with a drag bit. An innovative cutting and contact model is used to model rock/bit interaction. The dynamics of rotary and axial drive systems including hoisting system are also considered. The equations of motion are solved numerically to carry out parametric studies. The effects of various operational parameters are investigated for achieving a smooth and efficient drilling. The proposed model appears to capture stick-slip and bit-bounce as the simulation results qualitatively agree well with field observations and published theoretical results. The rotational and axial motions of the bit are obtained as a result of the overall dynamic behavior rather than prescribed functions or constants. The results show that with a proper choice of operational parameters it is possible to minimize the effects of stick-slip and bit-bounce and to increase the ROP. Therefore, it is anticipated that the results will help reduce the time spent in drilling process and costs incurred due to severe vibrations and consequent damage to equipment.
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Coupled Subsurface and Surface model: A Case Study
Authors B.A. Shammari, S.A. Putra, H.A. Nooruddin, I.J. Bellaci and A.T. ShammariAn integrated model that couples surface and subsurface models was developed for a huge carbonate oil reservoir overlain by a large gas-cap located in the Middle East region. The main objective of the integrated model is to quickly evaluate changes in production strategy and provide more accurate forecast of field performance than with conventional approaches where surface and subsurface performance are evaluated separately. Building a fully integrated model is a very challenging task, due to the complex nature of the field process, including compositional variations, NGL processing and evaluation of gas disposition options. The surface network model was developed to allow evaluation of liquid and gas velocity in the flowlines and trunklines, and erosional velocity and back pressure to every well in the network. Trunklines were modeled with detailed elevation profiles to capture the complex nature of desert terrain found in the field. The subsurface model is a huge resolution model with more than 60 million grid-cells. The reservoir simulation model is compositional, having nine-components and runs on a state-of-the-art in-house simulator, GigaPOWERSTM. This paper highlights the process in building the fully coupled model by a multidisciplinary team, including the subsurface model, wellbore models, surface network model, and the integration layer between those different standalone models. The paper also discusses the issues encountered during building the integrated model and how those challenges were resolved.
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Uncertainty of Porosity Measurement Correlations using NMR and Conventional Logging in Carbonate Reservoirs
Authors H.S. Al-Kharaa, M.A. Al-Amri, M. Naser and T.M. OkashaPorosity is a dimensionless parameter, defined as the ratio of pore volume filled with fluid to the bulk volume. Porosity is a critical volumetric parameter used to estimate the reserve for a given reservoir and it can be used as an input for reservoir simulation as well. In addition, porosity can be classified into two types, effective porosity (interconnected pores) and total porosity (connected and isolated pores). Total porosity is defined as the sum of effective porosity and clay bound water (CBW). In other words, total porosity obtained from conventional logging tools will be equal to effective porosity in the absence of clay and while it is not the case when clay is present. There are several methods used to estimate porosity of the formation. These include: measuring actual porosity in the core laboratory, computerized tomography (CT) scan, neutron-density logging, sonic tools, and NMR logging tools. All conventional logging tools (neutron-density and sonic logging tools) are strongly dependent on lithology, whereas NMR logging tool is independent of lithology. The NMR logging the most accurate compared to all other methods since it is independent of the reservoir lithology. It can be used to estimate the reservoir porosity directly without the knowledge of matrix lithology. On the other hand, conventional logging such as neutron-density and acoustic depend strongly on lithology which might yield incorrect porosity measurement. Several studies have been conducted to estimate porosity for both sandstone and carbonate reservoirs using different logging tools, however, determining porosity is a challenge in 2 IPTC 17260 complex and unconventional lithologies. In sandstone, the presence of shale and clay minerals will affect the response of all porosity tools. Carbonate is even more complicated than sandstone due to its heterogeneity and triple porosity system (pores, vugs, and fractures). In addition, the assessment of porosity measurements accuracy using NMR logging will be considered in this study. An attempt will be made to develop an empirical correlation from NMR data to obtain reliable porosity estimation. In this work, more than hundred NMR reading tool were used to develop empirical correlations to estimate the free fluid (FFI) and Clay bound Water (CBW) for Arab D reservoir. This can be used as a checking parameter for the used cutoff values by the service company to ensure full compliance with the measured values in the laboratory. The correlations also will optimize the logging tool time and reduce the operation cost. Results of pre-study (SPE-168110) showed that a clear criterion to divide the formations into dolomitic and clean formation (pure limestone) should be established to get more accurate result. In the dolomitic formation, correlations for CBW showed R of 0.96 and for FFI R is 0.99.In addition, in clean formation, correlations showed for CBW is R of 0.98 and for FFI R is 0.99.
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Thinly Bedded Reservoir Characterization, from Qualitative to Quantitative Approach, Case Studies in a Cenozoic Basin of Malaysia
Authors B.P. Kantaatmadja, G.S. Thu, R. Masoudi, M.B. Othman and M.N.B.A. RahmanThe limit of resolution of seismic data is a complex issue that involves not only wavelet frequency, phase characters, data quality (S/N), interference, tuning, but also criteria on how to measure resolvability, which can hamper confident lithology, porosity and fluid prediction of thinly bedded reservoirs. Widess‟s classic paper (1973) concluded that for thin beds (below λ/8 wavelength), the seismic character, peak/trough time and frequency do not change appreciably with thickness, and also amplitude varies almost linearly with thickness, which goes to zero at zero thickness. Thus, λ/8 of wavelength is considered to be the fundamental limit of vertical seismic resolution which depends on velocity and mainly frequency. Tirado‟s work (2004) revised Widess‟s model, which is not applicable to the real reflection, and concluded that as the bed thickness decreases, there is a gradual increase in the peak frequency, but below a certain thickness (at some fraction of tuning thickness), the peak frequency rolls off and return to the peak frequency of the wavelet at zero thickness. Thus, the key factor in determining seismic resolution is by enhancing the frequency spectral bandwidth which, nowadays, can be effectively achieved either by acquiring Broadband Acquisition or conducting Broadband Seismic Re-Processing. We demonstrated various case studies on thinly bedded reservoirs using qualitative and qualitative techniques in a Cenozoic basin in Malaysia. The qualitative techniques involve the -90° Phase wavelets with Relative Colored Inversion, Spectral Decomposition, and ThinMAN broadband spectral inversion. The quantitative approach includes an integrated multi-disciplinary technique combining with Cascading AVO Simultaneous inversion and Stochastic Inversion calibrated with conventional and SHARP-OBMI logs, which together, significantly enhance imaging of the thinly bedded reservoirs. This unique integrated workflow has been applied in the field study, resulting in an increase of about 30% of hydrocarbon in-place volume, and has been successfully validated with available production/well data as well as newly drilled wells.
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Reservoir Characterization And 3D Static Model In Tight Carbonate, Open Up Reserves, Tuba Reservoir Sabiriyah Field, North Kuwait
Authors S. Abd El-Aziz, W. Bryant, C. Vemparala and S. Al-RasheediThe Sabiriyah Tuba Reservoir has significant hydrocarbon resources in place with a high degree of reservoir rock and fluid heterogeneity. Until recently, it received marginal development attention, and was considered one of the ‘Minor Reservoirs’ of North Kuwait with limited opportunity for production enhancement. Improved reservoir Characterization and the development of a 3D Static model, together with Horizontal Completion technology have now opened up new opportunities for an accelerated development strategy. The Tuba formation represents a carbonate ramp with different lithofacies association from more proximal depositional setting to more distal environments. Even though the northern area of the field is represented by deeper facies, the reservoir quality shows comparable porosity and permeability trends. The porous and permeable aggradational and progradational carbonate of Upper & Lower Tuba respectively, constitute the main oil accumulations where reservoir quality is strongly controlled by structure, primary depositional fabrics, as well as extensive dissolution process. It has a significant vertical and horizontal variation in oil quality ranging from low 11-18 API oils to better quality 23 API oils. Current performance of the producer wells indicates that Tuba has the potential to enhance dry oil production. Tuba reservoir is divided into 3 main stratigraphic units, Upper, Middle & Lower and each unit is further subdivided into sub-layers. The geological layering based on sequence stratigraphy combined with 3D seismic data provided the framework for structural model. The high resolution model was achieved by generating 3D faulted grids and integrating all the components such as all the deterministic structure maps and petrophysical results in to one geocellular model applying different approaches and techniques. The model and visualization proved valuable in the interpretation of the primary depositional and secondary digenetic processes that left their imprints on Tuba rocks The study helped accelerate the development of the Tuba reservoir, and led to new Drilling & Workover opportunities that converted to >500% increase in Oil production. Additionally, from this study, an estimated increase in recoverable reserves of >60% would now support a long term development plan and reserves growth for North Kuwait.
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Well Accessibility Considerations in Well Completion Designs for Long-Reach and Deviated Offshore Wells
Authors S. Juyanty, M. Jeffry, D.M. Shivananthan and C.H. RohAA is a new gas field located offshore Sarawak currently under field development planning phase. The elongated field structure consists of multi-stack reservoirs that are located up to 15,000 ft tvdss. Two options for developing the shallow Phase 1 wells (down to AA300 reservoir) have been assessed; completing at either one or two wellhead platforms. To decide between the two options, the team needed to be confident about the ability to safely intervene these wells in the future, which triggered detailed accessibility analyses for all wells considering various intervention methods. Four main intervention methods assessed were slickline, braided line, electric line (E-line) and coiled tubing (CT). This paper provides the details of well accessibility analyses conducted during development planning stage. Sensitivities on the types of intervention activities, bottom-hole assemblies and friction factors are also studied. The findings from the study have significantly changed the well completion designs of the long reach deviated wells justifying use of smart wells. This systematic well accessibility approach was applied for the first time to replace the traditional rule of thumb of a simple 60 degree deviation used as a cut-off for well accessibility.
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Factors That Affect Gas-Condensate Relative Permeability
Authors S. Kalla, S.A. Leonardi, D.W. Berry, L.D. Poore, H. Sahoo, R.A. Kudva and E.M. BraunWhen the pressure in a gas condensate reservoir falls below the dew point, liquid condensate can accumulate in the pore space of the rock. This can reduce well deliverability and potentially affect the compositions of the produced fluids. Forecasting these effects requires relative permeability data for gas-condensate flow in the rock in the presence of immobile water saturation. In this study, relative permeability measurements have been conducted on reservoir rock at a variety of conditions. The goal has been to determine the sensitivity to interfacial tension (which varies with pressure) and fluid type (reservoir fluids, pure hydrocarbons, and water). The results show a significant sensitivity to fluid type, as well as an interfacial tension sensitivity that is similar to that reported by other researchers. For obtaining relative permeability data that is applicable to a specific reservoir, we conclude that laboratory measurements should be conducted at reservoir conditions with actual reservoir fluids. The measurements reported here used a state-of-the-art relative permeability apparatus of in-house design. The apparatus uses elevated temperature and pressure, precision pumps, and a sight glass with automated interface tracking. Closed-loop recirculation avoids the need for large quantities of reservoir fluids and ensures that the gas and liquid are in compositional equilibrium.
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Collaborative APC Project Management
By P. SinghLNG Industry is in next era of optimizing and maintaining huge LNG capacities, where QATARGAS is contributing 42 MMTPA out of QATAR’S Visionary delivery of 77 MPTA LNG. Mega trains also brings together range of complex technologies and a challenge to automate and cruise control by these technologies with emphasis on reduction in emissions, better asset utilizations, energy efficient operations and controlled product specifications. QATARGAS operates its world class facilities with state of art optimisation tools implemented on On-Shore facilities starting with Inlet reception unit, Condensate Stripper, Fractionation Units, Liquefaction Units, Acid Gas Treating Units, Scrub Column, Acid gas enrichment units and Sulphur recovery units. QATARGAS operates its 7 LNG trains with 62 such large APC controllers and overall asset wide linear plant wide optimizer to negotiate and control various constraints within different units with an objective to maximize revenue with minimum energy index operating with the defined operating /optimisation envelop of operating assets.
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Application of Statistical Analysis on Vertically Variable Azimuthal Anisotropy: Case Study from a Carbonate Field Offshore Abu Dhabi, UAE
Authors S. Nakayama and K. BelaidIn the mature oil and gas fields offshore Abu Dhabi, reservoir properties required for static and dynamic models are relatively well-defined by a number of wells. On the other hand, seismic data are considered as a fundamental and primary source to determine and optimize well placements. Azimuthal velocity analysis using wide-azimuth 3D-2C OBC seismic data is performed on different formations where several drilling issues arose mainly due to two dominant tectonic forces in the region. The results reveal different magnitude and orientation of azimuthal anisotropy from overburden to reservoir level. Available FMI and DSI logs confirm consistency between seismic and borehole-driven azimuthal anisotropy. The analysis results are also in agreement with the regional geology and tectonic history. Azimuthal anisotropy analysis generally provides two types of information such as the orientation of anisotropy and the amount of anisotropy. The amount of anisotropy can be simply quantified while the information obtained from the azimuth data has some complexity as it is a periodic function. In this respect, a statistical model of the bipolar von Mises distribution is proposed to determine the preferred orientation of azimuthal anisotropy. The model also provides the concentration parameter that can quantify the degree of preferred dimensional orientation of azimuth data. Additionally, we show utilization of the azimuthal anisotropy analysis particularly on a non-fracture layer and its benefit to field development by the analysis of spatially varying mud weight prediction.
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Selection of Power From Shore for Offshore Oil and Gas Developments
Authors E. Thibaut and B. LeforggeaisWith a step out distance of 170 km and a design power of 55MW, Martin Linge offshore gas field, will be the longest AC submarine cable power supplying an entire offshore Oil and Gas platform from the shore. This field development comprises a platform with a jack up rig and a Floating Storage Offloading unit. This paper discusses the criteria to consider and select a power from shore concept instead of an offshore Gas Turbine power plant which is the current practice in the offshore Oil and Gas industry. Since in a first approach, for such long step-out distance, the choice of power from shore would be to select a DC transmission line, the paper discusses the design and the main technical challenges of this long step-out AC transmission development. Finally, the system approach, required for the development of the onshore and offshore part of the project, is described.
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Shallow Gas Confirmation by Slow Shear Wave Using New LWD Sonic Quadrupole Technology
Authors N.T. Son, A. Pradana, M.F. Hashim, M.Z. Aznor, A. Ahmed, A. Zolhaili, C. Maeso, W.F. Kent, H. Yamamoto and S. BramantaA re-development drilling campaign was planned for a brownfield in South East Asia. In previous campaigns, conducted between 10 and 20 years ago, limited data had been acquired in the shallow to intermediate sections. At the time extensive wellbore stability issues led to stuck pipe events and lost wireline strings. The absence of data from the shallow sections resulted in difficulties for seismic ties and identifying potential shallow hazards. The planned development phase involved long 12 ¼ in hole sections from a very shallow depth, with extensive borehole builds from vertical to 68°. In order to acquire shallow hole information, log data requirements led to a long bottom hole drilling assembly including multipole sonic measurements. The sonic measurements were acquired using a new multipole sonic tool in an 8 inch collar. Real time quality control using transmitted coherence peaks and pumps off stations gave confidence in the real time compressional data. Post processing of the full recorded mode waveforms confirmed the real time values. For shallower intervals Leaky-P dispersive processing allowed determination of formation compressional signals (differentiating formation and mud where they are close in value). Formation shear values were always slower than the mud and so were not available from the Monopole signal. The Quadrupole mode contained slow shear through the majority of the section. Shear data was seen in the range of 275 – 920 usec/ft. The compressional and shear data is the shallowest borehole sonic data acquired in the field to date. Presence of shallow permeable gas was confirmed by good quality shear sonic data in a highly unconsolidated formation. The sonic data was also used for seismic inversion. Historically acquisition of shallow interval sonic data has been problematic in South East Asia due to soft formations and wellbore stability issues. This paper demonstrates the use of LWD mulitpole sonic to address this challenge to reduce drilling risk and geological uncertainty.
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Qatargas Flare Reduction Program
Authors I. Bawazir, M. Raja and I. AbdelmohsenQatargas produces 42 Million Tonnes Per Annum (MTA) of Liquefied Natural Gas (LNG). The Qatargas facilities comprise seven LNG Trains, including four of the world’s largest mega-trains, which were commissioned between 2009 and 2011. Routine baseline flaring is encountered during normal LNG plant operations due to the essential requirement to maintain purge gas flow within the flare system to prevent air ingress and consequent explosion hazards. During unplanned facility trips, restarts or planned facility shutdowns, process gas is also flared per operational requirements. Qatargas has made significant progress in reducing flaring from its LNG trains in line with the increased national focus on flare minimization and the Company’s desire to reduce its emissions and carbon footprint. This has been made possible through operational initiatives on source reduction, increased plant reliability, reduced shutdown/start-up flaring and a sustained focus on flare minimization facilitated by multi-disciplinary Flare Management Teams (FMTs). Enhanced acid gas recovery and operational excellence initiatives on source reduction and plant reliability at Qatargas’ older, conventional LNG trains have successfully reduced flaring by more than 70% between 2004 and 2011. A comprehensive project is currently underway at the LNG mega-trains to reduce current baseline purge flaring by approximately 70%. Qatargas is also undertaking a long-term capital project to install interconnections between LNG mega-trains to re-route gas encountered during process events rather than flaring. Additionally, Qatargas’ pioneering Jetty Boil-off Gas Recovery (JBOG) Project, which will commence operation in 2014, is expected to reduce LNG loading flaring by over 90% and recover approximately 600,000 tonnes per year of flared gas. This paper provides an overview of Qatargas’ flare management approach, the Company’s main drivers and challenges for flare reduction and the various initiatives currently underway to manage and minimize flaring. These include the major capital projects noted above as well as enhanced awareness, monitoring and reporting, and operational source reduction successes.
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Sweet Spots Identification in a BCG Play in Sichuan Basin China
Authors Z. Jinying, G. Biwen, L. Xi, D. Mueller, S. Antipenko and A. RolphUnconventional resources are considered to be a game changer for near-term and future energy, the huge resources of unconventional gas worldwide will be critical to the world economy. The JinQiu (JQ) block, joint operated by Shell and PetroChina, is located in the northwest of the Sichuan basin, with target reservoir in upper Triassic Xujahe formation (from T3x1 to T3x6). The play concept for the JQ block is a basin centered gas (BCG) play which consists of overpressured, stacked alluvial feldspathic litharenite reservoirs with a very high net-to-gross (N/G) and low porosity and permeabilityties in T3x2 and T3x4 members, and low N/G, low porosity and permeability calcarenites interbedded with calcareous coaly shales in T3x3 and T3x5 members. Major challenges that the operators face to produce these unconventional resources are identifying subsurface sweet spots and utilizing techniques such as wellbore stimulation to generate commercial projects. The process of sweet spot identification in the JQ block includes the following steps: 1) confirming and updating the play concepts from wells early in the play appraisal phase; 2) determining key geological, geophysical and petrophysical elements for the positive well results to define subsurface critical risks factors such as play concept model, reservoir properties, resource density, predicted facies distribution (i.e. channel orientation and distribution) and fracture geometries etc, and 3) follow play based exploration workflow by overlaying critical risk maps for each element to define areas of common risks segments (CRS). Using the results from these CRS maps and knowledge obtained from the positive well results enable us to identify sweet spots for future exploration, appraisal and development drilling. After this study was completed, one additional appraisal well used as a blind test was drilled and finally got an encouraging well testing result. Conclusions from this study are that, for unconventional plays, such as this BCG play, sweet spotting is important to define developable hydrocarbon resources, where all subsurface disciplines (geology, geophysics, petrophysics, reservoir engineering, completions and drilling) should be integrated to drive the decision making. In addition, the configuration relationship of fractures geometries, predicted facies distribution and resource density plays a critical role in the sweet spotting for BCG play exploration, appraisal and development.
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Study of Damage Evaluation of Hydraulic Fracturing to Reservoirs
More LessClassic hydraulic fracturing analysis is based on tensile strength of rock, failure criteria of fracture mechanics or Mohr-Coulomb criteria. The existing hydraulic fracturing theories consider little of permeability of fracture reservoir and effective fracturing range, which is exactly the purpose of fracturing. On the other hand, when evaluating effect of massive hydraulic fracturing (MHF), there may be lots of fracture initiation points and cracks due to large range of MHF, which brings huge challenges to numerical calculation of hydraulic fracturing. MHF will have an effect on a large range of reservoir and accompany in-line micro-earthquakes, which indicate that lots of hydraulic fractures of different scales and directions are generated. Therefore, there will be difficulties to analyze cracking and propagating and estimate geometrical parameters by tensile criteria or fracture criteria. Even if the classic method is feasible, processing of element grid after rock failures will be a problem. Aguilera (1995) considered shear failure criteria as failure criteria of rocks and proposes fracturing theory of divergent or branched cracks, and that explains the generation of in-line micro-earthquakes in hydraulic fracturing. But the present analysis is just a qualitative method but not quantitative method. In fact, the basic goal of hydraulic fracturing is enhancing permeability of reservoirs as large as possible rather than producing one or two fractures. Analysis of fracturing effects is analyzing the influence of effective fracturing range on reservoir permeability. While the existing hydraulic fracturing theories just consider propagations and fracture initiations of one or two cracks but little of the quantitative estimation for effective fracturing range. Hence it is necessary to find a better mechanical method to make up deficiencies of the existing fracturing analysis and overcome the difficulties of processing element grid after rock failures. This study introduces continuum damage mechanics (Gurson damage model) to hydraulic fracturing, analyzes theories and techniques of hydraulic fracturing of porous reservoirs in terms of continuum damage mechanics and discusses damage effects of hydraulic fracturing to reservoirs. An analysis evaluation system of hydraulic fracturing continuum mechanics is set up, and by using damage theories, a method of analyzing hydraulic fracturing in fissured porous reservoirs is discussed.
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Underbalanced Drilling Technology for Unconventional Tight Gas Reservoirs
Authors H. Qutob, K. Kartobi and A. KhlaifatThe increased demand for more sources of clean energy such as natural gas from unconventional reservoirs has forced the industry to explore the more challenging tight gas reservoirs. Tight gas reservoirs constitute a significant proportion of the world’s natural gas resource and offer great potential for future reserve growth and production. However, to meet future global energy demand, access to tight gas reservoirs requires innovative and cost effective technical solutions. Yet, tight gas reservoirs are often characterized by complex geological and petrophysical systems as well as heterogeneities at all scales. Exploring and developing tight gas accumulations are both technically and commercially challenging due to the large subsurface uncertainty and low expected ultimate recovery per well. Appraisal of deep tight gas reservoirs offers many challenges, including production rate predictions when wells are drilled overbalanced. Overbalance leads to near wellbore damage to the rock matrix and fractures. Damage to natural fractures intersecting the well can prevent their detection leading to missed productive intervals. In addition, the operating environment is very challenging and that affects the decisions for data acquisition. The use of saltsaturated mud systems creates a contrast and uncertainty in the data. Hence, the quality of data acquired is compromised. In the 80’s hydraulic fracturing of deviated wells was the method of choice for developing tight gas reservoirs worldwide. Although sound in principle, in practice problems were experienced and caused either by poor cleanup due to fluid incompatibility, erosion of surface facilities or early water breakthrough due to fracturing into the water leg. In the 90’s horizontal drilling became common practice as new drilling technologies developed and proved to be very successful in many tight gas fields. However, conventional drilling operations introduced foreign fluids and solids into the reservoir which lead to several different formations damage mechanisms that prevented the identification of the gas production potential from these wells. In the late 90’s underbalanced drilling (UBD) was introduced, mainly to avoid the frequent drilling problems associated with total losses into these tight gas reservoirs. However, significant productivity gains were also observed and this became a key driver to apply the same UBD technology in tight gas fields. This paper provides a technical overview of the state-of-the-art UBD technology used to develop unconventional tight gas reservoirs. Two real case histories from eastern Jordan and South West Algeria will be presented and discussed.
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Permeability Multiplier Prediction using 3D OBC Seismic Data
Authors T.M. Matarid, K. Ibrahim and M.S. IbrahemThis work describes an approach in characterizing fractured reservoir of upper Jurassic Carbonate using seismic azimuthal anisotropy. The ultimate objective of this study was to attempt to map permeability multiplier inter-well for the contribution to the simulation model and the subsequent development plan of an oil field offshore Abu Dhabi. The azimuthal seismic anisotropy for fracture prediction method showed fractures that are similar to those indicated by well methods and therefore seismic can be used to detect natural fractures between wells. The confidence in the seismic fracture prediction method’s ability to capture information about fracture in Carbonate reservoir has increased if the well data are accurately integrated. The study interval exists in the dense zone of the Upper Jurassic reservoir with total thickness of 120’. The fractures evidence have been compiled from well data, such as Core, FMI, orthogonal shear sonic, production test, multi-arm caliber….etc. Present day stress is captured from induced fractures direction, borehole breakout, offset field stress map, Eocene structure map and world stress map. All compiled information’s indicated maximum horizontal stress of N10°-30°E direction. The four sectored wide azimuth seismic data set have been fitted to an ellipse to find out the fast and slow velocity direction and the difference between those velocities. The Interval Velocity is sensitive to Lithology, porosity, pore fill; the Vint-Slow is sensitive to the minimum horizontal stress. The lower the VINTslow, the less the minimum horizontal stress, which allows the fracture apertures to be more open. It is observed that the seismic anisotropy map for fractures showed a dominated direction (NNE-SSW) that match with present day stress field. The azimuthal Vint records current day stress field, not paleo-stress field. Good correlation between well permeability multiplier and the fractures map, particularly at the two reference wells. Following the analysis of the azimuthal seismic anisotropy maps such as azimuthal amplitude and interval velocity, a good correlation has been observed between the seismic anisotropy components and the production well test. The two seismic anisotropy components that showed a great deal of link with the computed well permeability multiplier are the computed slow interval velocity and the anisotropy azimuth deviation from the known present day stress. Therefore, the following equation has been written to invert those azimuthal seismic components into permeability multiplier. The resulted map showed match at both input wells and one blind well. Perm. Mult. = ( X * Vint Fast-Slow ) + ( Y / Vint Slow ) + COS (Ref. AZ – Seis. AZ)
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Integration Of Seismic Variance Attribute With Stochastic Error Surfaces To Have A Better Definition Of Structural Uncertainty - A Case Study
Authors D. Ghosh, B. Al-Enezi and D. Al-MatarStructural uncertainty is defined by creating stochastic error surfaces built on control points. Uncertainty is zero at the drilled locations and varies smoothly away from the wells. The other factor that enhances uncertainty is fault-zone. This study aimed at generating a composite model integrating these two determinants of structural uncertainty. The study is done on Mauddud surface in part of the Greater Burgan Field, Kuwait. The seismic guided surface was created incorporating tops of 13 drilled wells. Sequential Gaussian Simulation was used to generate stochastic error surfaces having normal distribution using these 13 zero value control points as input. Deviation of the actual Mauddud top from the given seismic surface was calculated to be to the tune of ±60’. The stochastic error surfaces were multiplied with a constant so that the surfaces closely represent the perceived uncertainty captured in these drilled wells. Seismic variance attribute was used to capture the uncertainty in fault zone. Variance was extracted on Mauddud surface from the variance cube generated. This variance surface was normalized with minimum and maximum values 1 and 6 respectively to use it as a multiplier to the stochastic error surfaces. The assumption was that the uncertainty will increase six times where there is maximum variance. The stochastic error surfaces were multiplied by the normalized variance surface to get the composite uncertainty. This uncertainty model was used to predict the uncertainty of Mauddud top in some wells drilled subsequently. The actual tops were found to be within the P10-P90 range except for a graben well where it was beyond the range. This study thus provided a model to quantify the range of uncertainty in predicting tops taking into account both distance from control points and uncertainty associated with fault zones as captured by seismic variance.
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Investigating the Dynamic Three-Dimensional Loading Effects on Perforating Guns Imposed by Shaped Charges
Authors G.G. Craddock, W. Zhang, J. Wight, J. Rodgers, T.S. Glenn, M. Serra and T. BettenmannModern developments in shaped charge technology have resulted in greater explosive loads being used on perforating guns, which has stretched the capacity of perforating guns into uncharted territory. Traditional gun design approaches and standards use collapse pressure calculation and swell measurement with overloaded charges as design verification methods. The extremely complicated interactions between explosives, fragmented casings, and the gun wall are evaluated on an empirical basis, and the nature of these interactions is not well understood. In this paper, a new design model is presented that augments traditional design approaches and provides gun designers with better data on gun system structural performance, including the effects of phasing, shot density, and charge type. The loads imposed on the gun body by the explosives are multidimensional because of the spiral arrangement of most shaped charges. The resulting dynamic response of the gun body is therefore quite complex and requires three-dimensional (3D) analysis. High-frequency bending, torsion, and tensile loads are expected. The casings are typically fragmented, and some of the larger fragments can impose high impact loads on the gun wall. A fully coupled computer model has been developed that incorporates the rapid explosion, casing fragmentation, and multidimensional structural responses. Multiple instrumented surface tests were performed to validate the dynamic 3D model. Proprietary testing techniques were used to extract gun internal pressure history and gun stress history at multiple locations immediately following detonation. Redundant strain gauges were used, and shots were repeated to ensure the integrity of the data. This paper presents the instrumented gun test setup and results, along with the newly developed 3D simulation model and shock hydro model results. This paper also presents validation of the newly developed 3D model through comparisons with test data.
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Revisiting Reaction Kinetics and Wormholing Phenomena During Carbonate Acidising
Authors X.W. Qiu, W. Zhao, S.J. Dyer, A. Al Dossary, S. Khan and A.S. SultanWormholing during matrix acidizing of carbonate reservoirs is known to be predominantly mass transfer limited. Mass transfer coefficient, controlled by (1) the fluid injection rate and (2) the acid diffusion coefficient, dictates the speed and profile of the wormholes. Injection rate is easily obtained from the job execution, whereas the diffusion coefficient is intrinsically a hidden parameter of the fluid and reaction conditions. Acid diffusion coefficient data used in modeling the wormholing processes are commonly obtained at 1000 psi system pressure, which is too low to represent realistic reservoir conditions. In order to properly quantify the acid penetration inside the formation, the diffusion coefficient of acid acquired from high-pressure reservoir conditions should be used. In this study, we investigate the effects of diffusion coefficients of HCl acid as it reacts with calcite. We use a rotating disk apparatus to obtaine the CO2-impacted kinetics at downhole conditions. The test results show that the diffusion coefficient of the HCl acid is much lower at high pressure than low pressure at the same concentration due to the impact of CO2 produced by the HCl-carbonate reaction. At higher pressure, more CO2 tends to stay in an aqueous phase, which slows down the reaction of HCl and the carbonate formation. For example, at 150 °F, the diffusion coefficient of 15% HCl at 3,000 psi reduced 50% of its original value when at 1,000 psi of 15% HCl. This new set of kinetics data is then implemented in a 3D wormholing model to predict wormhole morphology and penetration velocity. The model uses a CT-scan rendered porosity field to capture the finer details of the rock fabric. Simulation results of fluid flow coupled with reaction provide new insights on how acidizing design models should be improved to more accurately quantify wormhole penetration, which then leads to more accurate production forecasts.
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An Evaluation of Digital Rock Physics Technology for the Prediction of Relative Permeability and Capillary Pressure for a Middle Eastern Carbonate Reservoir
Authors K. Guice, L. Lun, B. Gao, R. Gupta, G. Gupta, J. G. Kralik, R. Glotzbach, E. Kinney, G. Leitzel, J. Rainey, R. Kudva and M.O. Al JawhariDigital rock physics (DRP) has received considerable attention in recent years as an alternative to laboratory measurement, especially for the prediction of reservoir properties for which the right laboratory measurements are difficult to perform or require long measurement times such as the special core analysis (SCAL) properties relative permeability and capillary pressure. While measurement of these reservoir properties can certainly be challenging to execute, there is a long history of successful, high-quality laboratory SCAL measurements. Before adoption of a DRP approach to generate reservoir properties that have significant impact on expected reservoir performance, it is important that the uncertainties introduced by use of DRP are better understood. To this end, we have utilized samples from a large Middle Eastern carbonate reservoir to benchmark vendor DRP predictions of water-oil imbibition relative permeability and capillary pressure against high-quality SCAL results that were measured using consistent laboratory methods. Considerable scatter are observed in the DRP predictions that do not exist in the measured SCAL data and cannot clearly be attributed to sample heterogeneity. Wettability, which is an important input into digital rock predictions but is especially challenging to quantify in the laboratory, is shown to have a significant impact on DRP predictions of relative permeability and capillary pressure. Nevertheless, the dependence of the DRP results on wettability is inconsistent with the SCAL data. Given the additional scatter and inherent uncertainties associated with use of the DRP approach, we find that a high-quality laboratory program employing consistent test methods remains the best approach to obtain SCAL data to support reservoir definition development, and depletion objectives.
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Economics of Power Production from Forward Osmosis
Authors M. Jacob, O.F. Garnier and G. LebasForward osmosis (FO) uses an osmostic pressure gradient to induce a net flow of water from the solution feed (low salt concentration solution) into the draw solution (higher salt concentration solution) through a semi-permeable membrane. The osmotic pressure can then be converted into a hydraulic pressure used to run a Pelton turbine and to produce green electricity. The permeate flow is then always kept at high pressure (15-30 bars) to feed the turbine using a pressure exchanger; this technology is called Pressure Retarded Osmosis (PRO). Oil terminals are rejecting to sea large quantities of salty produced water (above 100 g/l) and there is a potential for the application of PRO using this produced water as the draw solution and the sea water, river or lagoon water as the low-salt feed solution. Forward osmosis between sea water and production water could be used to produce electricity with low additional environmental impact. A technico-economical study was launched to evaluate the potential interest of PRO technology to produce electricity on the Djeno oil terminal site situated in Congo. The calculated technical cost of electricity is from 350 to 650 euros/Mwhr, which is not competitive with other green energies. This high cost is mainly due to required bulk equipments and their related electrical consumption, the membrane cost being only 10% of the technical cost. So though the technology seems promising, a technical breakthrough on membrane permeability and mechanical resistance is needed to promote PRO as a competitive clean energy.
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A Novel Technique to Utilise Surface Data for Pressure Transient Analyses in Gas Producers
Authors H. Al-Kharaz, M.Z. Farooqui, A.M. Ansari and and Kapil ThakurPetroleum engineers rely on periodic acquisition of bottom-hole data to monitor changes in well and reservoir inflow characteristics, and to quantify well and reservoir parameters using Pressure Transient Analysis (PTA). However, the acquisition of this data, especially in an offshore high pressure and sour gas environment, presents many logistical challenges and operational risks, and can negatively affect expenditure and downtime performance. On the other hand, surface data is routinely available, sometimes with sufficient frequency and precision to carry out PTA. Surface data is affected by wellbore transients that must be taken into consideration for converting the surface data to bottom hole conditions with the accuracy required for proper analysis. This paper describes a novel technique to properly account for wellbore transient effects and convert surface data to downhole conditions to enable conventional PTA without the need for well intervention. The technique combines the transient wellbore modelling with a novel approach of defining coefficients in a modified bottom hole pressure equation which is described in the paper. Coefficients are calibrated using concurrent surface and downhole data sets and then utilised to convert future surface data to downhole conditions. The paper describes the findings and conclusions from a five-well pilot, which involved wells with a range of reservoir characteristics, single and multi-layer production, and with/without cross-flow. The pilot work compared PTA results utilising this technique and surface data with results generated using downhole data.
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Qatar Petroleum Experience in Implementing the Measurement Strategies for Custody Transfer, Allocation and Royalties
By C. BolivarFrom the reservoir to the final consumer sales point, the flow and quality related to energy is estimated, quantified, or in an ideal situation is measured with very low uncertainty. Organization of Petroleum Exporting Countries (OPEC) reference basket averaged $107.52/b in August, and the world oil demand growth was revised in 2013 by 25 tb/d (1), in the longer term, prices may reach $155/b by 2035 (2), additionally, energy consumption has been estimated to increase 54% from 2010 to 2035, fossil fuel will account with 82% (2). Considering these short and long term estimations, the proper management of the uncertainty levels related to measurement systems in the energy sector has an intrinsic financial risk exposure that has to be addressed, and in most of the cases, a clear framework has to be established and led by the reserves owners. Technology has been evolving to manage better levels of uncertainty, but it is an endless journey trying to find the “true value” in order to safeguard the net profits of the shareholders. In the case of National Oil Companies (NOC), this challenge is translated in major strategic paths that are fully linked to the long term vision of an entire nation, and if we consider the nations where the Gross Domestic Product (GDP) is propelled by the Oil and Gas sector, the discrepancies related to product measurement may create a tremendous impact in the domestic economy. In consequence, around the supply chain, where different parties are directly involved in energy custody transfer process, the transparency and clear measurement terms are required for the buying and sales transactions. In many of those cases, royalties payment is involved, this issue must be fully monitored and controlled by the NOCs, but clear terms has to be agreed with the International Oil Companies (IOCs) in order avoid financial losses due to sub-optimal measurement practices. Qatar Petroleum (QP) has embarked in an ambitious task to implement a “Measurement Strategy”, to be applied to all the Joint Ventures and Production Sharing Agreements Operators that are located in the State of Qatar (SoQ). One of the key elements in the Measurement Strategy is the creation of a common framework to operate the measurement systems in the SoQ. The complexity lies to boost this initiative in an environment where different players have already an intrinsic risk related to their own operations in terms of hydrocarbon imbalances due to measurement uncertainties, and every single operator could operates the measurement system with a different asset management strategy. This paper will present the case and the lessons learned from this implementation process in order to deploy an unique framework to manage the measurement systems, where, the approach utilized to manage the diversity from the managerial perspective was based in the Kotter method.
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A Study into Tubing Shear Stresses in High Rate Wet Gas Producers
Authors M.Z. Farooqui, L.B. Morshidi, M.S. Kersey, M.A. Bugti, A. Troshko and N.S. BerchaneThis paper discusses an approach used to assess liquid film erosion/corrosion effects in the tubing strings of sour, high-rate, wet gas producers. This was done as an alternative to API RP 14E, which utilises an empirical erosional velocity factor “C” to estimate maximum velocity limits to minimise the potential for tubing metal loss from erosional effects. Many RasGas wells are completed with a full L-80 carbon steel or a combination L-80/Corrosion Resistant Alloy (CRA) production string. Once on production, a thin iron sulfide scale develops on the tubing wall significantly retarding the rate of metal loss due to internal corrosion. However, shear stresses generated from the condensate/water film flowing along the tubing wall could potentially remove this protective iron sulfide coating and expose fresh metal to much higher corrosion rates. This paper describes the approach adopted to assess the magnitude of shear stress created across a range of flow conditions including well production rates, fluid properties, and completion sizes using transient 1D flow simulation and more detailed 3D computational fluid dynamics modelling. The results will be used to design future laboratory experiments to assess the effect of these stresses on the integrity and effectiveness of the iron sulfide scale in reducing corrosion rates.
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A Holistic Approach to the Development Stage of Shale Gas Resources
Authors M. Navarette, L. Chorn and M. MaucecSource rock reservoirs (SRRs) are found in conventional oil and gas basins. The development of a SRR depends on the geological, geochemistry, petrophysical, and geomechanical parameters, as well as economic constraints in the targeted area. While SRR exploration and appraisal methodologies are fundamentally different from conventional assets, the development stage takes on more similarities to conventionals. However, conceptual differences remain that require technical professionals and managers to alter time-tested approaches. Unconventional SRRs impose significant engineering constraints because reserves are spread across large compartmentalized stacked or layered reservoirs, which are highly heterogeneous and contain wide ranges of mineralogy. This paper is a continuation of the exposition on a holistic approach to shale gas and oil development, which has been developed in detail and encompasses more than 25 years of service company experience in US gas shale plays (Navarette et al. 2013a, 2013b). The objective of this work is to provide a guideline for acquiring and applying a better understanding and application of SRR reservoir quality and deliverability insights. The goal is to position geoscientists and engineers to maximize well productivity, improve hydraulic fracturing stimulation effectiveness, and optimize drilling and completion efficiency. This paper identifies critical paths and key technical elements or tasks associated with SRR field development. Previous data (seismic, logs, cuttings, mud logs, extended production tests, and optimized well construction and stimulation practices) acquired in the Screening and Appraisal stages are used. A methodical approach is presented that addresses the following key tasks: 1. Categorize critical SRR attributes and key learnings. 2. Confirm hypotheses tested in the Appraisal stages. 3. Establish drilling program plans for the best reservoir targets (sweet spots) with well location and lateral orientation. 4. Maximize the stimulation potential and recovery factor. This work provides a proven road map for the evaluation and development of SRRs. Critical paths with the associated key technical elements address and provide a project scope of challenges, which enables a holistic solution to successful unconventional SRR development.
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Sequence Stratigraphy Framework of late Early to Middle Cenomanian Rumaila and Late Cenomanian to earliest Turonian Mishrif Formations, Onshore Kuwait
Authors A.H. Youssef, A.P. Kadar and K.A. KaramA high resolution biostratigraphic and paleoenvironmental investigations were integrated with sedimentology and wireline-log-data to establish a sequence stratigraphic framework of Rumaila/Mishrif section, Kuwait. The biostratigraphic analysis of over 500 core/chips from 9 wells recognized six 4th order sequences over the study section. All the identified sequences correlated regionally. Three 4th order sequences were identified within the Rumaila Formation: RU100, RU200, and RU300. The RU100-SB lies on the boundary between the non-calcareous restricted shale of the upper Ahmadi Formation and the highly fossiliferous, calcareous marine shale at base of Rumaila Formation. The RU100 and RU200 sequences are represented by marine calcareous shale or marl containing common nannofossils and marine microfossils at their MFSs. The RU300-SB lies on top of the shallower facies, poorly fossiliferous highstand of the under-laying sequence. The RU300-MFS is indicated by abundant micro/nannofossils. This marine event is equated with the regionally known K130. The Rumaila/Mishrif contact is placed at the shift in facies from the deeper water facies of Rumaila to a shallower facies of Mishrif. The shallower facies of Mishrif is bioclastic wack/packstone enriched upward in rudistid and coralline fragments forming a fair/good quality reservoir. Three 4th order sequences were identified within the Mishrif Formation: MISH100, MISH200 and MISH300. The MISH100-SB lies on top of recrystallized wack/mudstone and packstone ending up with a dolomitic wackstone. The MISH100-MFS is indicated by planktonic foraminifers. MISH200-SB lies on top of Praealveolinid wack/packstone of the previous sequence. MISH200-MFS is indicated by planktonic and benthonic foraminifers. The MISH300-SB lies on top of the Praealveolinid wack/packstone ending up with lagoonal non-calcareous shale. The MISH300-MFS is indicated by planktonic and benthonic foraminifers. This marine event could be equated with the regionally known K140. The Rumaila is considered as a good seal all over Kuwait while the Mishrif is considered as a fair/good quality reservoir towards the south. Micritic matrix, moldic, vuggy and fracture porosity reservoir is represented in parts of MISH100, MISH200 and MISH300, while the rudist, coralline floatstone reservoir is existing within MISH300-HST of some areas. Geologic model is presented to show; depositional setting, paleoenvironments, basin configuration and geographic extension of different sequences.
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Advances in GTL Requires Effective De-Risking
More LessWith the realisation and start-up of Pearl GTL in Qatar - the largest Gas to Liquids plant in the world, a memorable milestone has been reached for both Qatar and Shell. For Shell, the journey started with a vision and ambition in the 1970’s to develop GTL technology, commercializing stranded gas and converting it to high quality hydrocarbon products as an alternative and differentiator to LNG. Following a successful commercial scale 14,000 barrels per day GTL plant application in Bintulu, Malaysia, the GTL technology and product marketing was well-matured for further scale up and was matched with the vision of Qatar to not only become the LNG capital but also the GTL capital of the world. The Shell GTL journey has been extensive with an ongoing evolution in applied technologies in syngas production, Fischer-Tropsch synthesis and product refining besides continuous development of new products and markets. Effective deployment of new technologies in highly complex and capital intensive GTL operations requires efficient and thorough de-risking processes for markets, technology and its operations. The commercial operations in Bintulu, along with additional dedicated industrial scale test units, continue to play a crucial role to test and develop new technologies and prepare products for market developments. This paper will cover elements of the development journey, with particular focus on the process of de-risking for new GTL technologies, operations and products. The Shell Gasification Process for syngas production is an example of a technology that evolved with considerable scale-up and could be effectively de-risked and subsequently successfully applied. An example of a new product development is the “clean burning and high energy” GTL Jet Fuel now used in commercial flights by Qatar Airways.
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Integration of a Geospatial Framework with a Suite of Numerical Models for Operational, Environmental and Regulatory Aspects of Cooling Water Usage
Authors E. Febbo, J. Duggan, V. Kolluru and S. PrakashUse of complex mathematical models and geospatial information systems (GIS) has traditionally been a mutually exclusive process. Spatial and temporal modeling is performed using a suite of well-established numerical models for a particular domain or area of interest (AOI) and outputs are produced for the same domain framework. GIS, on the other hand, allows integration for managing, storage, analyzing, connecting to perihyls, output (ie. hardcopy, softcopy) map and image products along with visualizing data for interpretation in two dimensions (2D) and three dimensions (3D) from many sources and different formats. A GIS system can include; marine data: biota, sediment types, water quality, hydrodynamic data, and ecological sensitivity information, in addition to atmospheric meteorological data. The ability to project and integrate results from numerical models in a GIS system could potentially be a powerful spatial decision support system (SDSS) for operational aspects of coastal and offshore industrial activities to support environmental management and for regulatory reporting requirements. The system would incorporate a web-based computing infrastructure where geospatial data can be accessible to many users with access controls set by data owners that are appropriate to needs. The vision is the implementation of integrated diverse multi-scale, multi-disciplinary spatial data with analytical and numerical models for environmental and industrial management. The initial SDSS developed in this stage of work integrates the physical and logical components of the modeling system into a GIS framework such that seamless interaction and functionality amongst existing GIS data sets and cooling water dispersion model scenarios can be further analyzed and visualized in a spatial format. The system will also have the flexibility to incorporate additional datasets, analytical or numerical models, and other decision making tools in the future. Such systems can assist users such as plant managers (adaptive management), emergency response teams (response planning and action) and policy advisors (impact assessment and planning). The recent emergence, although still in a nascent stage, of web-based, spatial referencing GIS tools show promise in many key aspects of environmental and operational management, research and public policy, including data storage, analysis, and decision making. Systems such as the SDSS developed in this work can help facilitate the use of these emerging technologies.
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Wireline Straddle Packer Microfrac Testing Enables Tectonic Lateral Strain Calibration in Carbonate Reservoirs
Authors T. Ihab, R. Naial, D.A. Moronkeji, J.A. Franquet and S.S. SmithWireline straddle packer microfrac tests have become an important technology in creating microfractures to measure in-situ formation breakdown pressure, fracture re-opening pressure, fracture closure pressure and stress contrast between reservoir and non-reservoir intervals. The formation tensile strength can also be estimated from the difference between breakdown and re-opening downhole pressures. This case study describes the use of microfrac tests measurements to validate and calibrate the horizontal stress profile in various intervals of the carbonate reservoir. Well-injection plans, cap-rock integrity assessment, shale reservoir fracture containment, stress contrast and minimum and maximum horizontal stress estimations can all be quantified from microfrac test measurement. Six straddle packer stations were tested for microfracturing in this study well. One microfrac test was repeated in one formation due to observed poroelastic effects in the fracture re-opening pressure responses. Poroelastic effects around the borehole occur when the pore pressure near the borehole increases with the injection cycles, thereby making it more difficult to effectively re-open the pre-existing induced fracture. When poroelastic effects are evident, it is important and recommended to record the first pressure fall-off cycle after the formation breakdown for fracture-closure identification. Subsequent cycles will indicate higher fracture closure pressures and therefore overestimate the minimum horizontal stress in the interval. This paper describes the pre-job modeling, real-time monitoring and post-job interpretation of straddle packer microfrac testing for recalibration of the geomechanical model to provide continuous logs of in-situ horizontal stress profiles over the entire interval.
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Horizontal Well Productivity Restoration - Successful Stimulation Application in a Large Onshore Field
Authors S. Tiwari, R. Singh, D. Prasad, P. Kumar, M. Jha, R. Tandon, A.K. Singh and G. DangwalThis paper discusses the step by step procedure to identify damage mechanism and remedial treatment in horizontal wells flowing with ESP (Electrical Submersible Pump) in one of the largest onshore field Mangala situated in Barmer, Rajasthan, India. Mangala field was discovered in 2004 and was brought on production with hot water flooding in August 2009 and is currently producing at plateau rate of 150,000 bopd (barrels of oil per day). The reservoir, in general, is of high quality with multi-darcy permeability, relatively viscous (15cp) and waxy crude (wax appearance temperature only 5 deg C below reservoir temperature). The Fathegarh is the main reservoir unit which is sub-divided into FM1 (top) to FM5 (base). FM3 and FM4 are dominated by well-connected sheet flood and braided channel sands having net to gross ~80%. These massive FM3 and FM4 sands have been developed with down-dip edge water line drive water injectors and up-dip horizontal producers. These horizontals wells (lateral length >500m) are completed with screens with ICD’s (Inflow Control Devices).The initial PI (productivity index) of wells has been of the order of 50-100 b/d/psi. However, with rise in water cut and increased withdrawal rate the productivity of these horizontal wells started to decline. This paper discussed the optimized production practice required to maintain optimum production rate from these horizontal wells. Due to the fact that even relatively shallow invasive near-wellbore damage may substantially impede flow; plan was prepared to identify the damage mechanism and accordingly engineer suitable remedial treatment. Envisaged damage mechanism included fines mobilization, asphaltene / wax dropouts and carbonate and sulfates scales. An inherent problem with these wells was poor acid distribution during matrix acidizing, especially due to high permeability in long horizontal sections. The low cost systematic stimulation design and placement technique resulted into the liquid PI restoration and improved ESP performance, which has been discussed in length in the paper.
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Barzan Completions Success Through Innovative Stimulation and Testing Technologies
Authors B. Clancey, M. Aly, M. Bugti, C. Shuchart, R. Sau, M. Grubert and A. FarahThe North Field Barzan Development was executed with focus on identifying and implementing effective completion solutions that addressed new technical challenges and operational constraints presented by the wells of this project. The primary challenges were in areas of matrix stimulation, spent acid clean-up, and production testing. Stimulation issues included implementing designs for a wide range of permeability contrasts, addressing stimulation vessel pump rate and acid capacity limitations, managing live acid corrosion due to sour environment, and assessing effectiveness without production logs. Spent acid clean-up operations required protecting downhole safety valves and achieving fluids composition criteria required for production into carbon steel pipelines. Production testing challenges included fluids modelling and equipment solutions that decreased Safety, Health and Environment (SHE) risk and operational complexity, while allowing accurate measurement of gas and liquids flow rates and obtaining required fluid samples. The solutions included improvements to the acid stimulation system chemical diverter and corrosion inhibition package, custom design and manufacture of a subsurface safety valve protection sleeve, adoption of well clean-up criteria tailored to pipeline and facilities requirements, evaluation of multi-phase flow meter and real time fluids analysis technologies, and development of a simplified multi-phase flow rate calculation algorithm based on choke manifold and fluids composition data. Implementation of differentiating technologies enabled cost savings and SHE benefits due to reduced flaring, execution of single stage stimulations, smaller test equipment layout, and innovative flow rate calculation techniques. Stimulation designs were demonstrated as successful based on interpreted changes in zonal flow contributions derived from minimum surface fluid compositional data. Wells were completed and ready for handover, meeting all requirements for the surface production facilities.
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Successful implementation of Through Tubing Technology (Sand Control and Gas Lift) in Challenging Offshore Environment as an Integrated Development Strategy for Sustainable Development of Marginal Fields: A Case Study
Authors A. Sharma, A.K. Singh, S. Anand, A. Parasher, A. Sharma and S. KaleWell AB-5 was drilled & completed in a marginal field in offshore West coast of India. Initially well produced only gas, till the oil bearing sands were perforated & it was being put on commingled oil & gas production. Through tubing sand control was installed in the well in view of continuous sand fill observed post perforation due to unconsolidated sand formation. Over the period of time, formation pressure depleted and the well eventually load up & died in absence of any mode of artificial lift on the unmanned platform. The Challenge was to unload & activate the well using gas lift in a commercially viable manner, avoiding expensive Barge based operation without having the said facility & provisions available. Since no Gas Lift Mandrel was present in the upper completion, a Thru-tubing Gas lift technique using retrievable straddle packers with GLV in between & conveyed on slick line was being adopted. A temporary arrangement of nitrogen tanks, pumps & surface set up for subsequent well unloading was organized. Further, a 20 T modular crane was installed on the platform after a detailed platform structural load analysis for spotting the surface equipment. Detailed NODAL analysis was being carried out for modeling the required nitrogen rates and the well performance at different gas lift parameters. Post GLV installation, nitrogen was pumped thru the annulus via the GLV, installed against circulating SSD, into the tubing. This Paper not only describes the Job design, technique implemented & challenges overcome during successfully activating a theoretically dead well to approx. 1000 BOPD production, thus establishing the viability of Through Tubing Sand Control (TTSC) & Thru-Tubing Gas Lift (TTGL) technologies but also delivers an integrated development strategy for sustainable development of marginal fields. The same technology is now being implemented in other water loaded wells of the field having similar technical and logistical constraints.
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Advanced Slim Hole Logging Tools for Precise Mapping of Hydrocarbons and Lowering Drilling Cost
By J.J. RajivDue To The Emergence Of Advanced Slim Hole Logging Technology (ASHL) with an advanced silhoutte and advances in drilling technology, there is a general preference to drill smaller diameter wells due to the comparative cost advantage, which also incubated for silhoutte of Precise MAPPING OF HYDROCARBONS In recent times, this preference has led some wireline service companies to start to offer open hole formation evaluation services with slim tools having a diameter in the 2” to 2½” range. At present, most of the traditional petrophysical measurements can be acquired utilizing slim log tools. In addition, several“specialized” measurements, such as x dipole sonic, formation pressure testing, and resistivity imaging can also be acquired. The use of battery, computing memory technologies has allowed these tools to be deployed using a broader range of convenient techniques allows for reduced risk in the entry of slim hole wells. The provision of slim hole logging services has created an opportunity in the industry to leverage these tools for the economic development. Therefore, short horizontal sidetracks, well re-entries tests deeper horizons can be drilled and logged successfully.
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In-situ Residual Oil Saturation And Cluster Size Distribution In Sandstones After Surfactant and Polymer Flooding Imaged With X-ray Micro-computed Tomography
Authors S. Iglauer, M. Sarmadivaleh, C. Geng and M. LebedevWe imaged a sandstone at connate water saturation, residual waterflood oil saturation, residual surfactant flood oil saturation and residual polymer flood oil saturation at high resolution in 3D with a micro-computed tomograph. We measured oil saturations, porosities, residual oil cluster size distributions and oil cluster surface areas on each image. We found that the waterflood and polymer flood reduced the oil saturations significantly (from 68.4% initial oil in place to 38.3% after waterflooding and 28.5% after polymer flooding). The surfactant flood was ineffective, which is probably due to the formulation we used and/or the fluid equilibration times we applied. The residual oil cluster size distributions and cluster surface area-volume relationships followed power-law relations, consistent with previous experimental measurements. We conclude that micro-computed tomography can enhance understanding of pore-scale fluid dynamics significantly.
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Accurate 3D Seismic Interpretation of Large Braided Delta Reservoir and Outcrop Analogs in Northwest China
More LessThis paper presents a first discovered braided delta images (area of 562.5 square kilometers, depth more than 3400 meters) with perfect river channels by accurate 3D seismic interpretation in the hinterland region of JR basin in northwest china. We can clearly identify micro facies like the main channels in the delta plain, underwater distributary channels in the delta front, mouth bar and sheet sand from the very fine 3D seismic images. Methods are discussed for identifying and dividing the features of braided delta sediments, using sequence stratigraphy, well log characteristics, core observation, 3D seismic data and outcrop analogs. The most effective and visual methods to reveal the characteristics of this special geological body are 3D seismic interpretation and outcrop analogs. Based on high-resolution sequence stratigraphic framework and well drilling, a work program focused on the fine description of this large braided delta reservoir has integrated accurate 3D seismic interpretation and outcrop analogs, which include: synthetically seismic attribute analysis, spectrum analysis, seismic waveform classification display, 3D coherency interpretation, logging constrained seismic inversion, 3D visualization Interpretation and outcrop studies. This method is a key to do a multi-angle research, and to find out the distribution law of favorable sedimentary facies belt. Matching the modern outcrop sedimentary observation, accurately identify geophysical response of special geological body from 3D seismic images has greatly promoted present oil exploration. The high quality of this complete braided delta images will not only provide a new typical braided delta geologic model for geologists to do deep studies, but also be very useful to further develop the similar reservoir at home and abroad.
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Greenhouse Gas Emission Reduction and Tailgas Maximization At ORYX GTL
Authors N.P. Saravanan and K. VyasORYX GTL, a joint venture between shareholders Qatar Petroleum and Sasol Synfuels International, is a pioneering gas-toliquids (GTL) facility that produces premium diesel fuel, naphtha and LPG. The objectives of this paper are related to Greenhouse Gas (GHG) management at ORYX GTL: it aims to a) identify the various sources of GHG b) describe the methodology to quantify GHG emissions c) identify various opportunities to reduce GHG emissions, and d) provides a case study on GHG emission reduction through utilization of tailgas as fuel in fired heaters. The paper is organized in two sections; the first section presents a brief overview of the ORYX GTL process, identifies the various GHG emission sources, quantifies the GHG emissions and describes the concepts and options to reduce GHG emissions. The second section describes a case study on the opportunity to optimize fired heaters to make use of tailgas and steps that can be taken to make use of these opportunities. A brief overview is also provided on projects executed by ORYX GTL to support the company’s strategy of optimizing sustainability and stability by reducing GHG emissions. The major GHG emission sources from the ORYX GTL facility are broadly classified as combustion and flaring emissions. The GHG emissions at ORYX GTL are derived from estimates and calculations taking into account the composition of fuel streams, the energy content of the fuel, available measurement data, emission factors and mass balance approaches. It was found that flaring of tailgas contributes significantly to the release of GHG emissions from the ORYX GTL facility. The GHG reduction was achieved by making use of Advanced Process Control techniques, utilization of tailgas for fuel, and recovery of low pressure vent gases to use as fuel in process heaters. The use of tailgas as a fuel to fired heaters increased from 10% to 90-95% of total heat duty since start-up. The increase of tailgas as fuel resulted in the reduction of natural gas as fuel, improving the carbon efficiency of the plant and thus reduced the environmental impact. In 2012, a 23% reduction in GHG emissions was achieved compared to 2011 levels due to maximizing tailgas utilization as fuel and stable plant operations. The results from this study highlight that a further reduction of GHG emissions is achievable by focusing on plant stability and flare reduction projects.
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Waterflood Optimization and its Impact Using Intelligent Digital Oil Field (iDOF) Smart Workflow Processes: A Pilot Study in Sabriyah Mauddud, North Kuwait
Authors M.Y. Khan, H. Chetri, L. Saputelli and S. Singherms. The transformation of raw data into information is achieved through intelligent, automated work processes, which are referred to in this paper as “smart workflows.” These smart workflows assist engineers with daily well surveillance activities, aid productivity, and help improve the speed and quality of their decision-making process. The workflow presented is related to waterflood management; however, it is part of a family of smart workflows (e.g., electrical submersible pump [ESP], subsurface waterflood optimization [SWFO], and smart production surveillance [SPS] workflows), which have been discussed in other work. These smart workflows and a commercial software, Oil Field Manager (OFM) for Decline Curve Analysis (DCA), have also been used in waterflood optimization for the optimum production allowable selection, with the ultimate goal of improving asset performance. This paper shares how these smart workflows are used for waterflood optimization and illustrates a case study of an injection pattern optimization and its impact on production. Comprehensive monitoring of the waterflood has been performed using real-time data through iDOF smart workflow processes, illustrating the analysis of real-time data, which includes pump intake pressure, flowline pressure, water cut (WC), and flowing bottomhole pressures. Other data used include static bottomhole pressure, production log results, and production flow tests. Monitoring is planned in such a way to understand waterflood movement within the reservoir from injector to producers and its impact on the production behavior of the surrounding producers. A positive response in terms of pressure maintenance and production increase has been observed and confirmed using various analytical tools.
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Empowering Women in the Workforce: Leadership Roles
By M. YousufGlobal general perception of leadership roles. Worldwide leadership roles are traditionally held by men. While the share of women in the workforce is increasing, it remains difficult for them to reach senior positions, which are mostly held by men. The Qatar National Development Strategy 2011-2016 seeks to increase the number of women in leadership roles by 30 per cent. Perceptions in the GCC that have traditionally limited career advancements for women. A number of cultural, organisational and personal challenges hamper women from reaching senior positions. Women are perceived to work responsibilities. In addition, traditional views on what constitutes appropriate spheres for women’s employment influence education choices for education and promote occupational discrimination. How to promote women to leadership positions. Research and evidence indicate that the appointment of women as top managers can positively improve the performance of a company. Global corporations, conscious of the value of gender balance at all levels, are more eager to hire and promote women. Developing professional women’s skills in decision-making and leadership help them realise their full potential. Examples of development opportunities include providing training, instituting career development initiatives and mentoring programs, and ensuring networking opportunities. Sustaining continuous growth for women in leadership roles. Today, some professional women in Qatar are already in challenging leadership roles. We need to ensure that we sustain these current positions while encouraging continuous growth. [Actual paper will review statistics and demographics for GCC, and in particular State of Qatar, and how they align with the Qatar National Vision 2030 for Qatarization].
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Barzan Gas Project: Clean Source of Energy Supporting Qatar’s Vision
Authors W. Bacon and E.M.M.R. Al-KuwariRasGas Company Limited (RasGas), on behalf of Qatar Petroleum and ExxonMobil Barzan Limited, is in the execution phase of the Barzan Gas Project, constructing two of the largest natural gas processing trains in the world to provide the State of Qatar with natural gas and associated liquids to fuel its growing economy. At peak, more than 30,000 people from over 40 nations will work together to execute this project in a safe and environmentally responsible manner. Natural gas from Qatar’s North Field, the world’s largest non-associated gas field, will be produced at a rate of 1,900 million standard cubic feet per day (mmscfd) by Barzan Gas Project offshore facilities, comprising three unmanned wellhead platforms, two subsea pipelines, and two onshore gas processing trains, all of which will be operated by RasGas Company Limited on behalf of Barzan Gas Company Limited. In addition to producing natural gas, ethane and field condensate for the domestic market, Barzan Gas Company Limited will export liquefied petroleum gas (LPG), sulphur, and plant condensate to the international market. Against the background of Qatar’s unparalleled rapid rise to prominence on the world stage, broad development of its economy, industry, commercial and social systems, and the hosting of high–profile international events, including the 2022 World Cup, ambitious and impressive expansion programmes are being undertaken, including a new airport, new seaport, metro and rail networks, doubling the number of hotel rooms, new schools, universities, hospitals, sports stadiums, conference and exhibition centres. Natural gas supplied from the completed Barzan facilities, a landmark development, will play a key role in supporting Qatar’s growth with a clean and reliable source of energy from world class production facilities, and in doing so, support the four pillars of the Qatar National Vision 2030: human development, social development, economic development, and environmental development. The Barzan Gas Project takes its name from a fortified tower built in the early 20th century located north of Qatar’s capital city Doha.
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Assessing the Biotreatability of Produced Water from a Qatari Gas Field
Authors A. Janson, M. Katebah, A. Santos, S. Adham and S. JuddBiological treatment is generally regarded as the most cost-effective method for the removal of organics from wastewater. Biotreatment of produced water (PW) presents many challenges when compared with municipal wastewaters or industrial waste streams. These challenges are typically linked to its high level of organics (including refractory organics) and salinity which can dramatically reduce biological floc formation and biomass settleability in conventional clarifiers. In a membrane bioreactor (MBR), an ultrafiltration membrane separates the treated water from the biomass and settleability is not a factor. This paper summarizes the results of tests conducted in Qatar with three parallel bench-scale membrane bioreactors to assess the biotreatability of PW from a local gas field. The testing was partially funded by Qatar National Research Fund which is testament to the importance of the research and the value it brings to Qatar and the world. The test program followed a Box-Behnken experimental design requiring 13 separate tests with input parameters of hydraulic retention time, solids retention time and temperature and response parameters of % COD removal and oxygen uptake rate (OUR). The results indicated ≈60% of the COD is removed through treatment in a membrane bioreactor. Statistically, only SRT was shown to be a factor in the percentage COD removal. At an SRT of 60 days, the average percentage COD removal was 62%, 4% higher the 58% average COD removal obtained at an SRT of 120 days. The OUR ranged from 0.10 to 0.19 mgO2/L-min and was shown statistically to be only dependent upon HRT with the highest OUR obtained at the shortest HRT of 16 hours. It is concluded that if biotreatability is shown to be cost-effective, it can contribute as part of an overall system to treat PW prior to recycle or reuse. This can reduce the facility's demands for fresh water and can thereby make existing potable water supplies available for other important uses.
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Driving Continuous Performance Improvement in Qatar’s North Field
Authors K. Akyabi, B. Clancey, F. Yurkiw, J. Babb and C. ChisholmRasGas Company Limited has been utilising the ExxonMobil Fast Drill Process to drive continuous improvement in drilling operations in Qatar’s North Field since its roll-out in 2005. Implementation of the process has resulted in significant increases in drilling performance and unique changes in operational practices. In recent years, continued North Field development in new areas has introduced unique challenges requiring innovative drilling solutions to continue to raise the bar in drilling performance. This paper details how RasGas has utilised the Fast Drill Process to identify and extend new performance limiters in wells of increasing drilling complexity. It also details the development and roll-out of a new Flat Time Reduction initiative that targets performance improvement in areas previously untouched by the Fast Drill Process workflow. The combined impact of these initiatives has resulted in another step change in performance and well delivery in more complex areas of the North Field. The performance improvements have accumulated cost savings in excess of $250 Million USD for RasGas and its Shareholders and have been achieved while maintaining and building upon an industry leading safety record. The performance improvement initiatives described in this paper are applicable for any large scale drilling campaign that requires increased Rate of Penetration (ROP), reduced plateau times, and accelerated well delivery.
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Best Practices in Asset Integrity Management System
More LessThe main objective of an Asset Integrity Management System (AIMS) is to ensure that the physical assets of facilities and pipeline system are operated in a reliable, efficient, and safe manner. Such motives can include the fitness to function safely and reliably; Consistency with all industry requirements and international standards; Compliance with company’s AIMS Philosophy, Operating & Maintenance Philosophy & Engineering Standards/Specifications as well as industry regulations. The AIMS goals shall demonstrate the persona of the company where an inward look into the company’s values and shall be subjected to evolution rather than revision. At Dolphin Energy Limited (DEL), the QHSE philosophy of - zero injuries, zero accidents, zero releases and no (minimal potential negative) impact to the public, the surrounding environment, and customers (Zero Leak Thresholds) was support by DEL’s implementation of the most appropriate technology available in the world along with KPI development in areas of defect management; specified tolerances; assessing infrastructure fitness-for-purpose & measuring the effectiveness of AIMS activities. This review paper will demonstrate DEL’s great focus on proactively understanding the type, extent, and the effect of all potential defects and by implementing a process where such learning is re-injecting and the results are structured and documented. The importance of regular internal reviews of the AIMS to ensure internal conformance, and the appropriate evolution of such approach as well as measuring its effectiveness are all important in making the right decisions in cases where emerging issues are supported and maintained. The AIMS approach shall be proactive where asset safety and reliability start with prevention by utilizing rigorous QA/QC related to design; materials, coatings, cathodic protection system infrastructure, and non-destructive examination. Participation in the initial project development teams & project approval processes and providing Integrity related input/approvals of projects design bases and construction activities are of an extreme value to Asset Management. Generally, aging infrastructure does become susceptible to the manifestation of time-dependent failure mechanisms where monitoring programs shall be structured usually into Operational Monitoring programs as well as large-scale monitoring programs such as (ILI) for pipelines. Any potential issue identified through risk assessment and/or monitoring activities shall be effectively mitigated to ensure Asset Integrity. Mitigation programs of AIMS shall also be addressed and may include regular preventative maintenance programs & repair activities. On the engineering Asset Integrity side, defect data validation studies and Failure Investigation & Root Cause Analysis, defect Assessments and feature growth analysis, risk based inspections (RBI) shall be considered within the AIMS overall structure. Another important component of AIMS is the utilization of application software that will assist in decision making which also can be based on a GIS based platform tool for integrity-related decision making. Such application can perform comprehensive Risk & Data Management capabilities. This review paper shall demonstrate how AIMS at Dolphin Energy Limited has been evolving in the UAE by highlighting the best practices in the industry.
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Produced Water Management for Sustainable Reinjection––Bench Scale Tests to Remove and Destroy KHI
Authors M. Al-Shaabi, K. Emadaddhi and D. RoquetDolphin Energy Limited’s (DEL) production scheme is based on a wet transport of well effluents from offshore platforms (DOL-1 and DOL-2) to the onshore treatment plant. At the onshore receiving facilities, sour gas is routed to gas sweetening, condensate is stabilized and treated and produced sour water is routed to water treatment units. Since the plant startup in 2006, non-chemically contaminated waste water is used for irrigation after treatment. Produced waste water and chemically contaminated waste water are re-injected into a deep reservoir without any major treatment further to H2S stripping, oil skimming, pH control and multi-media filtration. However, local authorities have expressed their concerns about the quality of water injected and the potential risk of long term injectivity loss. Indeed, as sealines need to be protected all year round against corrosion using a Corrosion Inhibitor (CI) and hydrate formation during winter by using Kinetic Hydrate Inhibitor (KHI), produced water recovered onshore is chemically contaminated with polymer based chemicals. As KHI could damage the reservoir, it has to be removed from produced water prior to reinjection. However, no technology was clearly available and referenced for this application. Dolphin Energy launched numerous bench scale tests with a third party laboratory to identify the best treatment scheme to remove KHI. The paper will first explain the overall strategy put in place to identify applicable processes. Then, it will describe the laboratory tests on produced water for KHI removal and destruction. Eventually, results will be presented and compared in order to conclude with applicable treatment schemes that would remove and destroy KHI from produced water for sustainable reinjection.
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CO2 Capture From Sulfur Recovery Units’ Effluents
Authors D. Roquet, I. Aslam and K. EmadaddhiDolphin Energy Limited (DEL) is considering reducing the native Greenhouse Gases (GHG) emissions from its Ras Laffan plant in the state of Qatar. One important source of native Carbon Dioxide (CO2) is the gaseous effluents from the two Sulfur Recovery Units (SRU’s). Dolphin studied the possible options for recovering up to 50 MMSCFD CO2 from the subject SRU’s effluents upstream the thermal incinerator section in the SRU using the existing infrastructures in its Ras Laffan plant. The recovered CO2 would be exported at medium pressure (MP, 7 bara) and/or high pressure (HP, 190 bara) to other users. The study investigated the possible options to recover and compress the CO2 product. Capital costs, utilities requirements, operating costs, carbon intensity savings, layout and electrical power supply were all studied. The study investigated the following technologies, which are based on amine solvents: • HP scheme with some feed gas compression to improve the performance of the solvent and reduce equipment size • LP scheme with low pressure efficient technology that does not need much feed compression • Revision of existing treatment scheme in the Sulfur Recovery Unit to perform Acid Gas Enrichment, Tail Gas Treatment and CO2 capture with minimum modifications The study considered that either (i) each SRU train will get its own CO2 recovery unit and compressors, or (ii) the SRUs’ effluents from both SRU trains will be combined before treatment. The paper will present main outcomes of this study and highlight specific requirements with regard to CO2 properties in terms of phase behavior, design criteria and Health, Safety and Environment.
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Reservoir Fracture Characterization and Modeling in a Shuaiba Reservoir
Authors R. Corbeanu, S. Nasoetion, K. Yang, M. Labiadh, R. Narayanan, M. Mubarak and K. HabibMassive mud losses, well logging, seismic data together with observed conformance issues and significant variation in well performance suggest a well developed fracture system in a regional Shuaiba reservoir. Proper characterization of such fractures plays a critical role in modeling reservoir fluid flow and production. Fracture corridors are the dominant fluid flow paths in Shuaiba reservoirs and are the focus of this study. Their spatial distribution and conductivity are characterized by integrated analysis based on drilling, logging, core, seismic, and well performance. Geological analysis, including tectonic/structure history, strain/stress variation, and rock mechanical stratigraphy are performed to better understand the fracture system. Overall well performance is clearly related to fracture distribution throughout regional fields. During early stages of production, before water flooding, conductive fracture corridors connected the underlying aquifer to producers and occasionally resulted in premature water breakthrough in high strain areas. Following the implementation of water injection, these fracture corridors also connect some injectors and producers. As a result, continued development requires recognizing and mapping these fracture corridors. This is done by acquiring saturation data in recent horizontal wells. Together with borehole image data, the width and configuration of fracture corridors can be characterized. A practical approach is taken in 3D fracture modeling. Fracture corridors are interpreted in 3D by integrating all static and dynamic data available. Their conductivity is classified into high, mid and low using dynamic data and mud losses. Fracture distribution and flow properties are related to or constrained by geologically more predictable attributes including reservoir curvature, current day stress field, structure pattern, and mechanical stratigraphy. Using the approaches described above, an improved characterization of the fracture system was developed and exported to a geologic model for use in a dynamic simulation model to better predict waterflood performance.
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Greenhouse Gas (GHG) Emission Verification at Ras Laffan City (Case Study)
By A.M. BuhidmaQatar Petroleum is implementing an accurate and auditable procedure for the Accounting & Reporting of Greenhouse Gas (GHG) emissions within Ras Laffan Industrial City (RLC). The procedure is based upon proven European practices and international and industry proven guidelines and methodologies in determining emissions caused by CO2, CH4 & N2O as a result of process combustion, acid gas removal/generation and flaring. Participating companies are all Oil & Gas processing companies and Power and Water Generation companies in RLC with combustion installation having a fuel rated input exceeding 20 MW. Each participating company submits quarterly & annual GHG emissions reports supported with accounting & reporting plan and spreadsheet calculations for verification by an accredited third party verifier hired by Qatar Petroleum. As a result, a Positive Verification Opinion & Statement are issued by the same verifier for each participating company that had proved it’s compliance with the requirements of the applied QP GHG procedure and international guidelines. This paper describes the initiative that Qatar Petroleum deployed in the preparation for the GHG verification process and the implemented methodology in accounting & reporting of GHG emissions at RLC, the achieved progress in uncertainty of the reported GHG data in three consecutive years (2010 – 2012) and the lessons learned for future improvement. The role of Qatar Petroleum in initiating, monitoring & control of GHG emission verification at RLC is also addressed in this paper.
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Improved Statics Model of a Marine 3D Seismic Dataset Through the Application of Refraction Statics Tomography Processing, Offshore Qatar
Authors C. Lange, C. Hanitzsch, M.E. Zahran and G. TylerThis paper describes the refraction statics processing based on tomographic inversion of a 503km2 subset of a modern marine 3D seismic dataset acquired in very shallow waters offshore Qatar. The objective of the seismic survey was imaging of the Mesozoic interval from 0.4 – 1.8 seconds two way travel time below sea level. Characteristic for the study area is the presence of local shoal bodies, often associated with coral reefs at sea bottom and in the near surface below sea bottom. These features can have a significant effect on the imaging of seismic data and therefore the prospectivity assessment of the exploration area as their typically high velocity introduces distortions in the timing of events, i.e. false structures might be generated or true structures suppressed. Compensating for the reef structures in the statics model results in a more accurate image of the subsurface. This was achieved by applying first-arrival travel time tomography to obtain the shallow velocity information needed to calculate refraction statics corrections. Refraction statics tomography uses the first break travel time picks of the seismic data to derive a velocity model of the near surface. This velocity model is then used to generate static shifts to correct the data to a final datum plane using a known replacement velocity, thereby removing the velocity variation caused by the sea bottom and near surface features. The tomographic inversion algorithm for land data was adapted to marine data by including a new option to freeze the water column velocity, which should be constant and not taken into account in the velocity updates. Refraction statics tomography is superior to conventional refraction statics because the inverted velocity model reveals the lateral and vertical velocity variations in the near surface. The dense shot and receiver spacing of this data set provided a large number of first break picks for the tomographic inversion process and resulted in a stable near surface velocity model. The computed static shifts corrected for some of the time shifts observed below the sea bottom features. The application of refraction statics tomography in this study provided an improved subsurface image compared to the original processing.
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Development of an Online, Non-Intrusive Means for Detecting Onset of Formation Water Production in Gas Flow Lines
Authors S.A. Mohammed, M. Aggour, M. Fraim, A. Aboegila, M. Farooqui, H. Al-Kharaz, M. Ashkanani and M. MarmoushProduction of high salinity formation water with gas presents major operational and reservoir management challenges in gas reservoirs. Early detection of unexpected water production is critical for ensuring prompt action to prevent accelerated corrosion damage in surface pipelines and facilities if they are not designed to handle the produced brine. Several methods exist for detecting water in pipelines which are based on electrical, electromagnetic, and acoustic measurements. While most of the existing methods are intrusive requiring direct contact between the measurement probe and the flow stream, all such methods suffer from low accuracy of measurements and dependence on water composition and salinity. This paper reviews the various technologies that are in use to detect and measure water production. It also describes the theoretical background and the laboratory testing of a new means for detecting presence of formation water in gas flow lines.1-10 This work is part of a joint collaboration between RasGas Company Limited and Texas A&M University at Qatar (TAMUQ) aimed at developing a device which is: non-intrusive, clamp-on externally on the flow-line, accurate, and independent of saline water composition. This technology is based on neutron elastic-scattering and activation interactions. The laboratory testing is performed using simulated field conditions to determine the feasibility and accuracy of the measurement technique. Based on the laboratory results, a prototype device is planned to be constructed for field testing. Safety aspects of the process application both in the lab and in the field have been thoroughly examined and comprehensive safety measures have been developed and implemented per the health and safety regulatory requirements. The paper also presents the findings from a simulation study using the Monte Carlo N-Particle (MCNP5) neutron flux simulator11 to examine the feasibility of the proposed method and to properly design and optimize the experimental setup and procedure.
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Diagenetic Geobodies: Fracture-Controlled Burial Dolomite Bodies in Outcrops from Northern Oman
Authors V. Vandeginste, C.M. John and J. BeckertDiagenetic heterogeneities are difficult to predict in subsurface. Nevertheless, such heterogeneities can be crucial in hydrocarbon exploration. Diagenetic processes can significantly alter petrophysical properties of reservoir rocks, especially in carbonate rocks because of the reactive nature of the carbonate minerals. Dolomitization, i.e. the transformation of calcite (limestone) into dolomite, is a common diagenetic process in carbonate rocks. Description: an overview of the learning outcomes gained by studying fracture-related dolomite in outcrops of Oman and subsequent laboratory analysis over the last four years. A combined structural, petrographic and geochemical approach was taken to study three dolomite systems occurring in different stratigraphic host rock intervals. Application: Structurally-controlled dolomitization (i.e. dolomitization along faults and fractures) typically occurs in burial conditions, and the resulting strong permeability anisotropies caused by the dolomite textures can cause major challenges for hydrocarbon exploration. Results and Conclusions: Dolomite bodies in the Precambrian Khufai Formation are related to N-S to NNE-SSW fractures, whereas dolomite bodies that mainly occur in the Jurassic host rocks occur along reactivated WNW-ESE normal faults. These fracture-related dolomite bodies are generally less than 15 m wide, but can be up to a few hundred meters long. Late-diagenetic dolomite bodies were also recognized in Permian host rocks, where they occur at or close to the contact between Permian limestone and early-diagenetic dolomite. This late diagenetic dolomite system can be traced laterally for at least hundreds of meters and occurs in wadi’s about 40 km apart. Our data indicate that there were several dolomitization events in the geological history, generating dolomite bodies with different characteristics. Technical Contributions: This highlights the needs to understand the timing and structural setting of dolomite bodies in subsurface to improve reservoir management.
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Intelligent Wells' Performance and Reliability in the Northern Fields of Saudi Arabia
More LessIntelligent wells have become one of the best-in-class practices in the northern fields of Saudi Aramco with 153 intelligent wells equipped with downhole valve systems completed over the past 10 years. Different service suppliers approached the principle of producing through intelligent wells with their unique actuation mechanism and valve design. Therefore, many trail tests and piloting had been carried out prior to the mass installation of any system to ensure its reliability, functionality and operational suitability. Subsequently, the experiences gained from the operation of the installed intelligent wells over the past decade provided a whole new perspective into their operability, applicability and added value. This paper reflects on the experiences gained from the operation and maintenance of the installed intelligent wells through: * Comparison between the performance of different downhole valve’s actuation mechanisms used in the northern fields of Saudi Arabia with provision of their pros and cons. * Identification of their operational impact and suitability for a specific application environment. * Illustration of their components and the overall system’s reliability with logged surface and subsurface failures along with their impact on the well performance. * Suggestions to select the most appropriate intelligent well system to withstand normal as well as harsh environments while serving the production objectives. The paper also provides valuable recommendations to alleviate the operational and maintenance issues often encountered during the actuation of downhole valves.
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Intelligent-Field Technologies on a Mass Scale: Change for Efficiency Improvement
Authors F.T. Al-Khelaiwi, M.A. Zarea, M.N. Al-Khamis, A.A. Al-Ghamdi and M.A. Al-AmriThe Northern Area Oil Operations of Saudi Aramco has embarked on the installation of Intelligent Field equipment and innovative technologies on a mass scale for the past decade. It was noticed that the initial performance and utilization of such technologies were lower than expected. Therefore; a plan comprised of the following was devised to tackle these deficiencies: 1. Launching a major organizational restructure and assigning a dedicated team of specialists to look after the Intelligent-Field equipment and the real-time data transmission to the databases. 2. Establishing a tailored maintenance service contract with the providers of such technologies. 3. Developing an in-house training program for specialization in the operation, maintenance and utilization of Intelligent-Field equipment. 4. Launching of an innovative technology deployment and evaluation program where each technology is assigned to a technical champion who assumes full responsibility of the technology deployment process. 5. Initiating and maintaining state-of-the-art knowledge management system to track the progress, document the procedures and processes, and capture the lessons learned from the application of each technology. The implementation of these steps resulted in enhanced Intelligent-Field equipment performance efficiency. In addition, the utilization of real-time data — in advanced production and reservoir engineering analysis; such as automated well rate validation and allocation, production optimization and sweep monitoring — has improved due to the high availability and quality of the transmitted data. This paper will provide details of the holistic approach developed by Saudi Aramco for the installation and maintenance of Intelligent-Field equipment and all the implemented changes in the work processes to maximize their performance and tangible benefits. The success and value-added by implementing this generic approach will be illustrated through the high efficiency of Saudi Aramco’s Intelligent-Field equipment, which has been maintained at 99%.
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A Novel Approach to Water-cut Prediction in Deep Cambro-Ordovician Tight reservoir with Complex Hydrocarbon Charge, Diagenetic and Structural Growth Histories
Authors L. Mohsin, S. Al Busaidi, F. Jiroudi and M. Al LawatiIn deep tight shaly-sand reservoir, with complex hydrocarbon charge and structural growth history, it is difficult to characterize reservoir zones with high water cut from others with low water cuts and high hydrocarbon production rate, due to high resistivity readings of tight reservoirs. Deep reservoir “B” in Abu Butabul Field, NW Oman has been charged via two genetically and chronologically different hydrocarbon phases (oil then gas); during a complex deep burial digenesis and structural trap history. Due to the variation of Hydrocarbon properties of such tight reservoir, it has been difficult to analysis such a reservoir using conventional petrophysical evaluation methods. In this study, a modified version of the approach published by Ibrahim, Abd_Elmoula, Said Hasani, Sultan, Jahwari in SPE 130261 in which Ro (Resistivity of Rock saturated with Formation water) and SWirr (irreducible water saturation) used to distinguish water from hydrocarbon zones has been taken a step further in order to predict water cut in tight reservoirs (illustrated in the workflow below). After calculating wireline logs derived permeability, there are two elements to be calculated: KHw (Permeability of sands units filled with water * thickness of these sand units), and KHhc (Permeability of sands units filled with hydrocarbon *thickness of these sand units). The ratio of KHw/(KHhc+KHw) provides a mean of estimating percentage of the expected water production. This approach has been validated with actual water cut from production data. Using mathematical product of KHhc*Phie (effective porosity)*(1-SW) provides a mean to rank the wells in terms of expected Hydrocarbon productivity, which then can be contoured and utilized for reservoir fracturing program of the reservoirs in promising wells. Supporting case-studies and production test results are discussed in order to demonstrate the validity and rate of success of this workflow.Moreover the workflow has been integrated with seismic inversion derived porosity maps in order to delineate areas of larger hydrocarbon reserves, which consequently has obvious implications on reserves evaluation and subsequent field development plan.
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Polymeric Corrosion Inhibitors - a New Class of Versatile Oilfield Formulation Bases
Authors P.-E. Hellberg and A. ZuberbuehlerProduced (oilfield) brines are rich in dissolved salts and thus have high ionic strength as well as conductivity. Further, they are in contact with ferrous metals used for oil- and gasfield installations. Thus, the potential for electro-chemical corrosion reactions in these environments is high. The latent consequences are e.g. general metal wastage, pitting, embrittlement and cracking which all can lead to equipment failure, or even catastrophic results like major oil spills. One of the most abundant methods to mitigate such events is the use of organic corrosion inhibitors (CIs). No doubt, film-forming organic CIs are one of the most important oilfield production chemicals as ranked by volumes used globally. There is a constant need to develop new chemistry in this field, driven by requirements for more environmentally adapted products, lower dosages, higher performance and meeting new compatibility and high temperature/high pressure (HTHP) challenges. The development and testing of of corrosion inhibitors for oil- and gasfield (offshore) use has been thoroughly reviewed (1).
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New Technologies for Optimizing Energy-Fluid Input and Flow Assurance in Mature Assets
Authors J.L. Mogollón, T. Lokhandwala, F. Crespo, C. Hein, S. Rath and L. SayavedraMature fields are the backbone of global oil and gas production. In fact, 70% of worldwide oil production comes from mature fields. A great deal of knowledge about how to exploit mature fields has been gathered throughout the years. However, as more areas become mature, new situations and new challenges arise. Revitalizing these fields extends their productive life and offers significant opportunity to expand worldwide reserves. New technology is critical when trying to increase hydrocarbons extracted from a field beyond the original expectations. This paper highlights emerging techniques associated with five key aspects of revitalizing mature fields. These are: energizing the reservoir using water and polymer flooding on viscous oil fluids, enhancing reservoir deliverability through pinpoint hydraulic fracturing techniques, assuring optimal injectant placement using lasting, functional smart well completions, and improving the rod pumps by using linear lift systems. Also, while technology plays an indispensable role in revitalizing a mature field, cost control, risk management, and optimizing economics are equally important throughout the decision-making process. This paper describes the impact of each emerging mature field technique and discusses recent advancements in technology that enable a new, distinctive approach to increasing production and recovery during the mature stages of the life of a field.
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Elastic Full Waveform Inversion with a Permanent Seismic Source ACROSS: Towards Hydrocarbon Reservoir Monitoring
Authors M. Takanashi, A. Kato, J. Kasahara, S. Luth and C. JuhlinTime-lapse analysis plays an essential role in EOR (enhanced oil recovery) or CCS (carbon capture and storage) management. However, conventional time-lapse seismic often cannot capture differential signals from the target interval because of near-surface heterogeneity or poor signal-to-noise (S/N) ratio. We discuss a potential application of a permanent seismic source “ACROSS” (Accurately Controlled and Routinely Operated Signal System) that can continuously excite controlled seismic signals over years. The superior repeatability of ACROSS makes it possible to subtract any waveforms that do not change over time, and hence the temporal changes due to the fluid replacement at the target interval should be enhanced. Also, it is possible to consider reverse time migration or full waveform inversion rather than just the first arrival or P-wave reflection traveltime inversion, since ACROSS precisely controls the source signature. Both vertical and horizontal single forces are reconstructed by clockwise and counter-clockwise rotations of an asymmetric cylindrical mass. In our synthetic study, we assume that two ACROSS sources are installed at a CO2 pilot injection project in Ketzin, Germany. Elastic FWI (full waveform inversion) is tested with the assumption that the medium parameters (i.e., P- and S- wave velocities and density) before the injection are known. To prevent crosstalk caused by interference of P- and S-waves, we apply a wave separation technique by extracting the scalar (P-wave component) and vector potential (S-wave component) of the elastic wavefields. The simulation results demonstrate that this approach clearly delineates the P-wave velocity decrease caused by the fluid injection. The high-repeatability of ACROSS enables an application of elastic FWI for residual P-wave velocity, which may bring a breakthrough toward CO2 and hydrocarbon reservoir monitoring.
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Reservoir Characterization and Strati-structural Play of Minagish Formation, SE Kuwait
Authors P.K. Nath, S.K. Singh, L. Ye, A. Saleh Al-Ajmi, S.K. Bhukta and A.H. Al-OtaibiThe Middle Minagish (Minagish Oolite) of Berriasian-Valanginian age is oil bearing carbonate reservoir in the Minagish, Umm-Gudair and Burgan fields in Kuwait. This Formation was deposited in an overall eastward-prograding carbonate ramp setting. Spatial variation of lithofacies and reservoir quality such as porosity, permeability and saturation are mainly due to changes in the interplay of deposition, sedimentation and diagenesis within them. The challenge here is to establish a new play concept to ascertain the geometry & nature of reservoir properties in relation to depositional lithofacies in South-East Kuwait. In this study, a systematic approach has been adopted to integrate sedimentology, petrography, petrophysics, sequence stratigaphy and seismic amplitude & attributes to understand reservoir quality and distribution vis-a-vis depositional environment. Ten lithofacies were envisaged from core and petrophysical analysis, out of which peloidal, bioclastic and oolitic grainstone and packstone have good reservoir quality with intraparticle and moldic pores as well as good permeability. A 3rd order Sequence stratigraphic framework was constructed incorporating well and seismic data to identify genetically related reservoir facies and its distribution. A package of forced regression shoal facies is recognized where inner ramp coarse grainstone overlies outer ramp bioturbated pack/wackestone. Seismic amplitude anomaly and waveform facies classification was used to identify lateral facies distribution constrained with conceptual depositional model. 2D seismic inversion was judiciously used to visualize the geometry and spatial distribution of reservoir facies and a new play concept towards north beyond the area of field development. Locally developed shoal in inner ramp and patch reef & reworked carbonate were found to be good locales for porosity development and preservation. The sequence stratigraphic framework shows lateral continuity and cycle of vertical heterogeneity of reservoir architectures .These led to a new play concept of strati-structural play of Minagish Formation towards deep basinal part to the north of SE Kuwait.
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Integrity Management of a Complex LNG Facility
More LessRasGas Company Limited (“RasGas”) employs a Facility Integrity Management System (FIMS) whose primary objective is to create a frame work system to maintain the physical and functional integrity of RasGas critical assets. Programme design starts with grouping equipment by programmes aligned with equipment classes such as structures, pipelines and machinery. Equipment is prioritised by determining its criticality to operations based on health, safety, environment (HSE) and business consequences. Risk-based plans, the so called equipment strategies, are developed to mitigate risks and maintain the desired level of integrity and reliability. These equipment strategy activities are then built into an overall Integrity Programme that includes objectives, roles and responsibilities and practices to ensure operational integrity through the operating life of the equipment. This paper will explain the various aspects and objectives of the system, in particular the benefits of having such a framework in place, managing risk-based inspections, early risk identification, the continuous improvement cycle through data analysis and risk screening non-performed preventive maintenance activities. The Facility Integrity Management System within RasGas would be described with the challenges faced and the lessons learnt during implementation. Challenges in the programme design, development and implementation will be highlighted as well as the strategies and decisions made to overcome these. Particular focus will be given to learnings in the development, implementation and sustainment of equipment strategies, early risk identification and system management.
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Low-Salinity Polymer Flooding: Improving Polymer Flooding Technical Feasibility and Economics by Using Low-Salinity Make-up Brine
Authors E.C.M. Vermolen, M. Pingo-Almada, B.M. Wassing, D.J. Ligthelm and S.K. MasalmehPolymer flooding is a mature EOR technique, which is successfully applied in both sandstone and carbonate reservoirs. In ongoing polymer projects, make-up brine is either formation water, sea water or any available water sources like deep or shallow aquifers. In this paper we focus on the use of low salinity water as the make-up brine. The objectives of combining low salinity flooding (LSF) with polymer flooding are three-fold: • Using low salinity brine reduces the amount of polymer required to obtain the target viscosity, which may lead to significant cost reduction. • Combining the benefit of low salinity flooding with polymer flooding leads to higher oil recovery over conventional polymer flooding. • Enhancing the elasticity of polymers by using low salinity brine which may lead to reduced Sorw and increased oil recovery. In addition to the objectives mentioned above, the use of a low-salinity make-up brine can give other benefits, such as better polymer stability especially at high temperatures), lower sensitivity to polymer shear degradation, lower polymer adsorption and lower scaling and souring tendency. The paper will present 1- Experimental procedures for investigating the potential benefits of low salinity polymer on both the required polymer concentration and the oil recovery. 2- Experimental results for several field cases 3- De-risking activities that were undertaken to mitigate any potential negative impact of using low salinity polymer, in the areas of clay swelling, polymer shear sensitivity, mixing and adsorption. The paper concludes that low-salinity polymer flooding can significantly improve existing and anticipated polymer flooding projects by reducing polymer volumes and/or increasing oil recovery. Low-salinity polymer flooding provides opportunities to apply polymer flooding in high-salinity and high-temperature reservoirs, for which polymer flooding with produced or formation water would be technically unfeasible or uneconomic.
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Nano-Technology for Asphaltenes Inhibition in Cupiagua South Wells
Authors R. Zabala, E. Mora, O.F. Botero, C. Cespedes, L. Guarin, C.A. Franco, F.B. Cortes, J.E. Patino and N. OspinaFormation damage caused by asphaltenes precipitation in Cupiagua south field has a negative impact on the volatile oil production on the wells located in XL pad. Chemical Control of Asphaltenes precipitation has been tested in Cupiagua XL wells to extend the life of organic cleaning jobs. The history of the field shows the usage of diverse commercial asphaltenes inhibitors with organic nature and high aromatic content. Products based on nano technology were tested recently, in which nano-particles of nano-sized metal oxides and high solubility in formation brines are used to adsorb and to carry asphaltenes along the produced oil up to surface avoiding flocculation and precipitation in the reservoir and the near wellbore. In the experimental work, lab tests were run in core plugs taken from the target wells. Results showed ability of nano-fluid to restore the damage caused by asphaltenes; this improved the effective permeability to oil from 5.79 md up to 10.78 md. Lab results also showed as the nano-fluid could reduce the impact on induced precipitation of asphaltenes denoted by the value of effective permeability of 0.09 md oil under non-inhibition had shifted up to 2.54 md where previously 0.3 pore volumes of nano-fluid was squeezed. XL-4 and XL-5 wells were selected for assessing the effectiveness of the nano-fluids to inhibit the precipitation of asphaltenes. The first well cpxl-4 was designed with a volume of 220 barrels of nanofluid to reach 7.2 feet of penetration. The treatment has allowed gains in cumulative production of 118,000 barrels oil after 4 months of squeeze with the nano-fluid. For the second well cpxl-5 the volume of nano-fluid was reduced to 180 barrels and penetration radius was increased to 9.2 feet by using a larger volume of over flush.
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Tectonics of the Mozambique Margin Through the Integration of Gravity and Magnetic Modelling: the Rovuma Basin Case Study
Authors M. Gilardi, R. Longoni and G. SpadiniThe Rovuma Basin is located along the eastern margin of northern Mozambique and southern Tanzania, forming one of a series of continental passive margin basins that stretch along the coast of East Africa. The basin covers onshore and offshore areas for approximately 64,000 Km2. The correct definition of the geological evolution of an area is of primary importance for a proper assessment of its petroleum potential; in the present work an integrated approach, based on seismic interpretation, structural analysis and 2D Gravimetric/Magnetic modelling, has been applied on three different interpreted seismic sections to provide more predictive and reliable geological models. The Gravimetric/Magnetic modelling has contributed to the definition of the Rovuma Basin architecture by testing two possible geological scenarios: one with a shallow top basement surface and another with a deep top basement surface, both interpreted on seismic data. Through the integrated potential methods study one of the above scenarios has been validated. The results of the integrated workflow could be summarized as: - proper basement surface depth scenario definition; - description of the main structural lineament geometries; - basaltic bodies geometry and location definition; - characterization of continental, transitional and oceanic crusts and definition of a possible Continental Ocean Boundary (COB) location. The mutual support between the structural studies and potential method teams has been the key to improve the geological knowledge in frontier exploration areas.
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Satellite Derived Bathymetry and Digital Elevation Models (DEM)
Authors J. Siermann, C. Harvey, G. Morgan and T. HeegeIn 2010, Qatar Shell Upstream International B.V. (QSUI) re-entered Exploration in Qatar focusing on the relatively deep conventional Pre-Khuff gas plays with a view to discover additional hydrocarbons in the State of Qatar. In order to support Qatar Shell with the execution of onshore and offshore seismic programs, satellite imagery was used extensively to derive added value products in terms of shallow water bathymetry, seabed classification and onshore digital elevation models (DEM). For the offshore bathymetry and seabed classification products, 2m resolution multispectral WorldView-2 satellite scenes were processed following a data processing chain including the correction of atmospheric adjacency (increased radiance over water due to reflection of photons by the nearby land and their further scattering in the atmosphere), water surface and water column effects. The resulting offshore products had a spatial resolution of 4m and covered an area of ~700 km2. For the onshore elevation product, a 50cm WorldView-1 stereo image pair was processed using a photogrammetric stereo vision algorithm to generate a 1m spatial resolution DEM over an area of ~450 km2. The accuracy and quality of these satellite image derived products depend largely on the optical conditions of the satellite scene, the sensitivity of the satellite sensor and the accuracy of the calibration. Three types of independent control datasets were used to assess the quality and accuracy of the bathymetry and DEM; airborne LiDAR sounding transects, multibeam echo sounding swaths (offshore) and seismic survey lines (onshore and offshore). After correction for any systematic bias, the correlation of both products with the control data was found to be very good with <1m vertical error in general. Satellite image products are recognized within QSUI as a key technology to aid the planning and preparation of seismic operations and site evaluation by improving hazard identification and reducing field risk exposure early on in the project life cycle. In addition, cost savings were realized compared to more costly traditional acquisition methods. The seismic field conditions were assessed relatively quickly compared to the time frame required for traditional methods. This allowed the data to be included in commercial tendering which in turn resulted in sharper bids. In conclusion, satellite imagery in combination with the right processing techniques has the potential to provide an integrated wide area bathymetry and DEM coverage at relatively high resolution and low cost.
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An Abnormally High Pressure Zone have been Detected to be the Culprit of Many Well Integrity Issues in Dukhan Khuff Wells
By A.A. SultanAn abnormally high pressure formation caused the loss of a number of Dukhan Khuff Gas (DKG) wells. The Sudair formation has always been considered normally pressured throughout the Dukhan Khuff gas field area. However, this case study supports the author’s hypothesis that, contrary to that belief, Sudair can be abnormally pressured. Two DKG wells A and B were the subject of this case study. These wells experienced loss of integrity due to high annuli pressures and were recently worked over. The author’s abnormally high pressure zone hypothesis is based on actual real data from both of these wells. DKG wells were drilled more than thirty years ago. All 28 wells were drilled through the Sudair formation without any pressure or well control issues. However, at some point in time, most of these wells developed annulus pressure in one or more of their annuli. How did that happen? To answer this question, the author searched other operator’s experiences in the area. The search pointed out that the Sudair formation is not always normally pressured; it can also be abnormally pressured. We have seen reports of Sudair high formation pressure associated with high rate salt water flow, high rate gas flow and in occasions very low rate salt water flow. While the high rate flows are detectable, it’s the very low rate high pressure salt water flow that is almost impossible to detect. Another finding is that the Sudair formation pressures are neither equal nor uniform over a large area but rather different and localized. What could we have done differently thirty-five years ago? The answer is simply no thing because we did not have the knowledge and knowhow of today. However, there are lessons to be learnt, t’s to be crossed and i’s to be dotted.
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Multi-agent Collaborative Decision Making for Upstream Asset Management
Authors P. Xu, N. Subrahmanya, A. El-Bakry and C. ReynoldsUpstream assets are very challenging to manage because the components and processes involved are numerous, dynamic, and interdependent. Managing such assets requires execution of multiple technical tasks such as analyzing data, forecasting behavior and optimizing performance. While software tools are available to help engineers perform individual tasks, the goal of integrating cross-functional asset management tasks to achieve a greater level of automation, or even autonomy, remains elusive. As a result, most technical tasks are run and monitored by engineers; and interdependent tasks and cross-functional workflows are integrated through high-level human interaction.
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Magnetic and Gravity Data Acquisition in Deepwater: a new Frontier for the Potential Field Geophysics
Authors G. Gabbriellini, G. Spadini, E. De Marchi, M. Filippini, R. Finotello and D. IndrigoThe O&G industry is moving offshore into increasingly deep waters in order to explore for, develop and exploit hydrocarbon reservoirs in new frontier areas. Standard gravity and magneto-gradiometric acquisitions in such areas are usually performed with ship-borne and airborne techniques. This implies that, especially in ultra-deep waters, the measuring sensors are very far from the geological causative bodies, thus leading to a poor SNR. Eni E&P is committed to adopting and deploying novel proprietary approaches and tools in these challenging environments. As part of an ultra-deep water E&P initiative, Eni and Tecnomare have designed, developed and tested the “AUVG”, a new Autonomous Underwater Vehicle capable of carrying gravimetric and magnetometric instruments onboard for the acquisition of potential field data close to the sea bottom in ultra-deep water environments. The vehicle, which is carried by a supply vessel and launched from it near the area of interest, is autonomously capable of navigating underwater for up to 20 hours, reaching the sea bottom and starting the data acquisition, performing pre-programmed trajectories, avoiding unexpected obstacles, storing the entire data set and emerging in a predetermined position. The vehicle can be located using a radio, strobe lights and a satellite localizer. By means of a Wi-Fi data connection, it is also possible to download data and re-program a new geophysical survey. Gravimetric and magnetometric data acquired by means of an AUV in deep water are characterized by a much higher SNR as well as a higher spatial resolution. These improvements have been experimentally highlighted by a recent test carried out in deep waters in the Ionian Sea.
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Demonstrating the Competence of the Workforce
More LessThe oil and gas industry’s business landscape has changed. The trend is clear: being able to demonstrate the competence of the workforce is now and will continue to be business critical. The argument is simple: just having development programs in place and believing that they equip personnel with the ability to be successful in their job activities, is not enough! It is only when companies assure that all their employees are in fact competent in what they do, that they will deliver on their promises to shareholders, customers, and the community as a whole. Companies have naturally evolved their development methodologies to incorporate a competency program into their business framework. However, in this self-regulated industry not all programs are created equal. This paper describes elements that make up a robust competency program to align with industry practices and regulations. It also describes how a company may demonstrate the competence of its workforce to its stakeholders. The elements that make up a robust program includes: assessing employee’s competence on the job as a preferred methodology; using qualified and competent assessors to conduct assessments; emphasizing employees’ consistency and exposure in the application of the competency; verifying conformance to established processes; and ascertaining the validity and reliability of the competence information. The demonstration requires the company to prove that: it has competency processes in place; it has communicated the processes; and it is applying the processes while developing, assessing, and documenting personnel’s competence. During this demonstration, competence records are shown but the level of detail varies depending on the instance: pre-work, execution of work, and delivery of services. This paper introduces a compelling case for action to assure the competence of the workforce and work towards standardizing an industry-wide approach.
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