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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 - 50 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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