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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 - 20 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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