NotesNov-09NOTES:The papers listed here have been obtained by search SPE and IPTC papers post 2005 on the SPE's OnePetroThe papers relating to reservoir engineering have been catergorised for inclusion on the reservoirengineering.org.uk websiteThe affiiations searched were;Total No PapersReservoir Engineering RelatedBP551175Shell575279Chevron482238ConocoPhillips19168Marathon5537Total255129Schlumberger1130563Imperial College, London9553Heriot Watt University, Edinburgh235175(Anywhere in Article)Total35691717Total number of papers published post 2005 =10,00035% of papers published categorised

SCHLUMBERGEROrganisationSourcePaper No.ChapterSectionSubjectTitleAuthorAbstractSCHLUMBERGERSPE115707CO2IntegrityAssessing Long-Term CO2 Containment Performance: Cement Evaluation in Otway CRC-1Matteo Loizzo, SPE, Schlumberger Carbon Services and Sandeep Sharma, SPE, CRC, and Schlumberger Carbon ServicesAbstract CO2 geological storage is about pumping a reactive fluid underground and ensuring it doesn't find a way back to the atmosphere for a very long time possibly centuries. Potable aquifers and other permeable formations (e.g. hydrocarbon deposits) must also be protected against CO2 contamination. Wells are generally recognized as a weak spot in CO2 storage where containment can break down. This is because cement steel and elastomers can be corroded by CO2 and the ageing process will be accelerated by any defects in the cement sheath. It is therefore of critical importance to understand and characterize fluids and solids across the caprock. This has the triple aim of: verifying the soundness of the complex cementing engineering process evaluating the capacity of cement to provide short-term zonal isolation and providing measures that can be used to predict the evolution of cement and casing over the long term. This paper will focus on an in-depth evaluation of the annular material on the Otway CRC-1 well that is being used to inject CO2 in the CO2CRC pilot geological storage project. The evaluation will draw on the design and job data and on a detailed analysis of the high-resolution 3D cement imaging log to characterize the cement and ensure the long-term risk of containment breach is minimized. The essentially unpredictable nature of fault-free risk i.e. the unplanned events in a job otherwise designed and executed to the highest standards always requires a number of mitigation measures to minimize the residual risk of CO2 leaks. This paper will show that the adoption of a number of them on Otway (e.g. excess volumes and CO2-resistant cement system) have been essential in achieving the containment objectives. Introduction Cement slurries are exposed to a number of phenomena during mixing and placement that can lead to set cement properties that are very different from their design value. Density control problems (both for continuous and batch mixing) contamination channeling and fluid loss can and do cause slurry dilution/concentration and chemical incompatibility which in turn can have a major negative effect on the capacity of cement to guarantee hydraulic isolation and can even lead to premature gelling during placement and early job termination. It is currently hotly debated whether ten or more meters of competent cement well bonded to casing and formation would degrade during the expected isolation timeframe for CO2 geological sequestration wells (1 000s to 10 000 years). This is because competent cement although reactive if exposed to CO2 has a very low permeability of the order of 0.5 to 5 D; this low permeability means that most CO2 will travel by diffusion a very slow process over the length scale of a meter. Cement with a high w/c ratio however could have a much higher permeability less resistance to CO2 aggression and more frequent defects related to slurry settling. Defects such as liquid channels in cement can even provide direct pathways for CO2 leaks that couldnt possibly be healed by calcite precipitation during the CO2 attack. Some of the phenomena listed above can be predicted but cannot easily be controlled; others (such as fluid loss) can hardly be predicted at all. In any case they belong to the class of fault-free risk sometimes called residual risk: events causing sub-standard system performance that cannot be engineered away and that may happen even when job is perfectly executed. Mitigation measures must be adopted in this case to ensure a robust design. This is especially true for wells entering CO2 storage reservoirs where storage containment is a key performance factor and CO2-cement reactions may cause leaks to grow over time.SCHLUMBERGERSPE116422CO2IntegrityStress Estimation at the Otway CO2 Storage Site, AustraliaT. Brard, B. K. Sinha, SPE, Schlumberger; P. van Ruth, T. Dance, Cooperative Research Centre for Greenhouse Gas Technologies; Z. John and C. Tan, SPE, SchlumbergerAbstract We present an estimation of the full stress state between 0.5 and 2.1 km depth at the Otway CO2 storage pilot site Australia where the Cooperative Research Centre for Greenhouse Gas Technologies is conducting a large-scale demonstration project. This estimation is the first step of a geomechanical study on seal integrity. One principal stress is assumed vertical and of magnitude equal to the weight of the rock above calculated from the density log data. The vertical stress gradient is on average 22.01 MPa/km. Extended leak-off test data a borehole wall electrical image and dipole sonic log data in the CO2 injector CRC-1 are used to constrain principal horizontal stress orientation and magnitudes. Consistency of the stress model is then checked against the occurrence of breakouts using a mechanical earth model built along CRC-1 well. We conclude that the maximum horizontal stress direction is oriented N141 +/- 9oE. To first order principal horizontal stress magnitudes both follow a linear trend with depth. Results indicate minimum horizontal and maximum horizontal stress gradients on average equal to 15.98 and 18.13 MPa/km respectively corresponding to a normal stress regime. Introduction Warming of the climate system in relation with the radiative forcing of anthropogenic long-lived greenhouse gases in the atmosphere is beyond debate. In this process carbon dioxide (CO2) alone contributes to 60 percent of the total greenhouse gases. Carbon capture and storage (CCS) is recognized as a means to reduce CO2 releases in the atmosphere significantly. CCS is the process whereby CO2 emitted by massive stationary point sources such as fossil fuel-fired power plants is captured transported and permanently stored underground. Along with capacity and injectivity containment is agreed to be a primary function in geological storage performance. It must be evidenced that CO2 will and indeed does remain within the intended repository. In particular seal integrity must not be impaired by the mechanical effects associated with storage operations . Forecasting such effects requires a 3-dimensional geomechanical model of the site describing in-situ rock stresses fluid pressures and the poro-mechanical and strength properties of the formations. This mechanical earth model is coupled to a reservoir model to compute initial conditions at static equilibrium and to further simulate the stress path rock deformations and potential rock failure associated with CO2 injection . The initial state of stress is amongst the key parameters controlling the stress perturbation a rock mass can sustain and yet remain stable. This distance to failure envelope is particularly relevant when it comes to analyzing the stability of long term underground storage or disposal facilities for determining upper bounds to acceptable fluid pressure changes in both the injectivity at the well(s) and the storage capacity of a repository. Insofar as the stability of faults or the compressive strength of rocks generally depend on all of the three principal in-situ stresses it is necessary to estimate the full stress tensor as a function of depth. Yet no single measurement technique can solve for all the 6 independent components of the stress tensor at a point and so procedures for in-situ stress estimation at depth must combine complementary datasets.SCHLUMBERGERSPE116424CO2IntegrityCO2 Storage - Managing the Risk Associated With Well Leakage over Long TimescalesY. Le Guen, J. Le Gouevec, R. Chammas, B. Gerard, and O. Poupard, Oxand S.A., and A. Van Der Beken and L. Jammes, Schlumberger Carbon ServicesAbstract One of the major challenges associated with CO2 geological storage is the performance of the confining system over long timescales. In particular the occurrence of CO2 leakage through existing wells could not only defeat the purpose of storage but also badly affect human health or the environment. Indeed cement degradation and casing corrosion in injection production or abandoned wells can create preferential channels over time allowing migration of CO2 from the reservoir to shallower formations (e.g. aquifers) and/or to the surface. In this paper a risk-based approach is proposed for well integrity and confinement performance management. The approach based on Performance and Risk Management methodology (P&RTM) serves as a decision support tool. The major steps are (i) identifying the system and the sources of degradation through characterization and system analysis; (ii) quantifying their criticity through modeling in terms of probability and severity and (iii) establishing a risk mitigation plan. This methodology is based on experience in material aging and risk assessment of complex systems like nuclear structures where probabilistic simulations are performed. It accounts for all stakes involved in well integrity management and enables the full integration of uncertainties as part of risk estimation. The methodology presented here greatly improves common approaches based on Features Events and Processes as it quantifies risk levels. It provides useful and reliable tools to support decisions for well integrity management strategies or emergency plans. To that purpose mitigation actions such as characterization/inspection remediation (workover) design improvement or monitoring are valued based on a cost/benefits ratio. Moreover updating risk assessment with incoming data allows for an evolving vision of risk levels to optimize interventions in time. This approach is successfully applied leading to recommendations for safer and more efficient design maintenance and monitoring strategies.SCHLUMBERGERSPE121970CO2ManagementModelling - IntegratedOptimizing CO2 Injection and Storage: A New Approach Using Integrated Asset ModelingA. Primera, W. Sifuentes, and N. Rodrguez; SPE, SchlumbergerAbstract The reduction of greenhouse gas emissions in order to decelerate the global warming process could be achieved through the emerging process of geological CO2 storage. Also in terms of Enhanced Oil Recovery (EOR) the injection of CO2 as a pure component or as part of a mixture has proved to increase the productivity of oil and gas reservoirs. Optimization techniques have been applied independently to the reservoir and surface models leading to non-optimal solutions due to the non-dynamic integration between models. A recent trend of the industry is the integration of sub-surface and surface simulators to have a better representation of the fluid production/injection taking into account the constantly changing interaction between systems. The integrated approach has been used to integrate multiple reservoirs with common and advanced surface facilities to properly model the fluid flow behavior of the asset. Different injection variables facilities well completion number of wells have been included in the analysis and numerical reservoir simulation models have been integrated with a network. As CO2 is captured it is transported and re-injected to neighbor reservoirs as an enhancement process for productivity or for storage purpose. After proving the feasibility of facilities for CO2 injection as EOR process or storage the integrated approach has shown a more comprehensive solution that could be used for the design and further optimization of this type of projects. Analysis of reservoir properties as permeability temperature etc. is also taken into account in order to asses the viability of the CO2 optimal injection and storage strategy while minimizing cost. Finally integrated asset modeling also shows the flexibility to represent different types of settings such as CO2 source (reservoir and/or fossil fuel power plants) types of reservoirs and network scenarios. Introduction Global warming is becoming one of the most important problems of the mankind. Precipitations have been reduced considerably and the sea level and ocean temperature have risen. One of the most likely causes is the emission of anthropogenic greenhouse gases into the atmosphere where carbon dioxide appears as one of the main components. As a consequence several mitigation options have arisen in order to reduce the CO2 emissions. One of the most current and important options is Carbon Capture and Storage (CSS) where the CO2 is captured and separated from energy-related sources transported and final storage in a proper location. There are two important scenarios for storing CO2 emissions namely ocean storage and underground geological storage. The first scenario is still a very immature technology but environmental concerns have slowed down its development and more knowledge in the area is required. The second scenario geological CO2 storage is currently available through several commercial or pilot projects. Geological storage injects CO2 into either oil or gas reservoirs aquifers or coal beds. CO2 has been used in the oil industry as a method to enhance the recovery of hydrocarbons and this knowledge has contributed to extending the use of CO2 not only for enhanced oil recovery but also for long-term storage.SCHLUMBERGERSPE108540CO2Modelling - InjectionCompositionalSimulations for CO2 Injection Projects With Compositional SimulatorS. Hurter, SPE, D. Labregere, and J. Berge, Schlumberger Carbon ServicesAbstract The need for CO2 emissions reduction at a large scale globally implies that CO2 injection into the subsurface be undertaken in a greater variety of geological environments that has been the case previously. Often when the storage reservoirs are saline aquifers exploration data for proposed injection sites are extremely sparse. The special behaviour of CO2-water/brine systems (mutual solubility and chemical reactivity) adds complex processes such as dry-out salting-out chemical reactions to the dynamic model. Simulation in these situations is one of few means of assessing an injection site and testing various scenarios. The accurate description of physics and chemistry in numerical simulation tools is fundamental for understanding processes as well as designing appropriate injection or mitigation strategies. We present simulations of CO2 injection into saline aquifers with a fully compositional code that has been expanded and enhanced to include specific phenomena such as drying-out and salting-out. The examples illustrate the importance of pre-injection studies as the wrong injection strategy may severely impact injectivity putting the project in jeopardy. Introduction Selection planning construction and management of CO2 storage sites are still in its infancy. Only a few industrial scale projects are operating over the last 5 years such as Sleipner (Norway) In Salah (Algeria) and Weyburn (Canada)1 2 3. New challenges exist also for CO2 Enhanced Oil Recovery projects. Although decades of experience exist in a few specific basins and geological environments the need for CO2 emissions reduction at a large scale globally implies that CO2 injection into the subsurface be undertaken in new environments (offshore and in a greater variety of basin settings) and at volumes much larger than have ever been injected into the subsurface. In this paper we focus on injection into saline aquifers al-though the discussion and results presented herein may be useful for certain aspects of CO2-EOR. Special properties of CO2 (or gas mixtures in which it is the dominant component) enhance several processes when compared to injection or production of hydrocarbon gases. This is not only caused by the specific values CO2 properties exhibit such as density viscosity heat capacity interfacial tension among others but especially the strongly non-linear variation of these parameters with temperature and pressure4.For instance in the range of 80 to 90 bar (at 35C) the density and viscosity of CO2 increases by a factor greater than 2 while for methane the change is of the order of a few percent. The mutual solubility between CO2 and brine affects the injection process and flow properties in three ways: CO2 dissolves in the brine increasing its density CO2 dissolves in brine and reacts with water forming an acid and H2O dissolves or vaporizes into CO2 removing water from the brine and increasing its salinity as salt concentration increases leading to dry-out and salting-out. In this article we first discuss in more detail the impact of mutual solubility for CO2 storage in saline aquifers. Numerical implementation of these concepts is presented. Simulations for a pre-injection study for a CO2 injection illustrate aspects that are needed for designing monitoring and injection strategies. Injection of CO2 in Saline Aquifers Saline aquifer is understood here as a brine reservoir or geological formation with reservoir characteristics (porosity and permeability) with pores filled with brine. The term saline expresses that CO2 storage is planned in reservoirs not intended to be used as fresh water resources generally shallower than 1000 m so that often deep saline aquifer is added. The term saline formation is also used for the same reason. Geological formations with these characteristics are rarely the target of exploration. Information derives mostly from regional geology based on surface mapping few stratigraphic wells and large-scale seismic surveys. This type of work is mostly the domain of national and state geological surveys. Uncertainty due to sparse data coverage is much larger than for better known areas of hydrocarbon and mining exploration. Therefore simulations play an important role to explore a range of possible scenarios and help constrain geologic risk of potential CO2 storage sites.SCHLUMBERGERSPE115247CO2Reservoir DescriptionField StudyLithological and Petrophysical Core-Log Interpretation in CO2SINK, the European CO2 Onshore Research Storage and Verification ProjectB. Norden and A. Frster, GFZ German Research Centre for Geosciences, D. Vu-Hoang, Schlumberger Riboud Product Center, F. Marcelis, Shell International Exploration and Production B.V., N. Springer, Geological Survey of Denmark and Greenland, and I. Le Nir, Services Techniques SchlumbergerAbstract The storage of carbon dioxide (CO2) in saline aquifers is one of the most promising options for Europe to reduce emissions of greenhouse gases from power plants to the atmosphere and to mitigate global climate change. The CO2SINK project is a R&D project mainly supported by the European commission the German Federal Ministry of Education and Research and the German Federal Ministry of Economics and Technology targeted at developing an in situ laboratory for CO2 storage. Its aims are to advance the understanding of the processes involved in underground CO2 storage evaluate applicable monitoring techniques and provide operational experience which all contribute to the development of harmonized regulatory frameworks and standards for CO2 geological storage. The preparatory phase of the project involved a baseline geological site exploration and the drilling in 2007 of one injection and two observation wells as well as the acquisition of a geophysical baseline and geochemical monitoring in Ketzin located near to Berlin Germany. The target saline aquifer is the Triassic Stuttgart Formation situated at about 630710 m (20702330 ft) that is made of siltstones and sandstones interbedded by mudstones. A comprehensive borehole logging program was performed consisting of routine well logging to which an enhanced logging program was added for one well that record nuclear magnetic resonance and borehole resistivity images predominantly to better characterize the storage formation. A core analysis program carried out on reservoir rock and caprock included measurements of helium porosity nitrogen permeability and brine permeability. Carbon dioxide injection started in 2008 and will last for about 2 years. The paper focuses on the integrated approach of combining lithological and petrophysical data from both laboratory and well logging analysis predominantly for the reservoir/storage section of the Ketzin site. This method was successfully applied in two wells with extensive core data. In the third well where few core data exist the section was characterized successfully by analogy. Introduction Since the publication of the Intergovernmental Panel on Climate Change Report (IPCC 2005) geological storage of carbon dioxide (CO2) was recognized in the public as an important concept for reducing greenhouse gas emissions into the atmosphere. Notwithstanding technology the understanding of the storage geometry from the near surface to below the storage reservoir is mandatory. Another prerequisite for a successful operating storage project is the detailed knowledge of rock and fluid properties that do depend on pressure and temperature conditions. These data serve as an input for reservoir models and decisions on the injection regime as well as decisions on the monitoring of long-term CO2 migration after injection.SCHLUMBERGERSPE98617CO2StorageCO2 Sequestration - A Safe Transition TechnologyM. Sengul, Schlumberger Carbon ServicesAbstract Fossil fuel fired plants are responsible for the one third of the carbon dioxide (CO2) emissions which thought to be a major contributor to the current rise in the Earth's surface temperature. Reducing CO2 atmospheric concentrations by capturing emissions at the sourcepower plants or chemical unitsand then storing them in subsurface reservoirs is thought by many scientists to be a reliable solution until emission-free energy sources are developed and viable.The current options for captured CO2 utilization are; Enhanced Oil Recovery (EOR) Enhanced Coal Bed Methane Recovery (ECBM) Enhanced Gas Recovery (EGR) Food processing applications Mineral products Fertilizer manufacture Algae growth promoter Enhanced plant growth. The capture and storage of CO2 continues to accelerate as new projects are initiated and existing projects confirm the development scenarios. A crucial element in CO2 storage is reliable monitoring of CO2 migration behavior and storage volumes. An innovative seismic monitoring techniques has recently been awarded a U.S. Department of Energy (DOE) project that will examine the application of time-lapse (4D) seismic technology and advanced reservoir simulation to optimize CO2 EOR operations.Well design cementing completions techniques and long life cycle mechanical integrity assurance are currently subject of many R&D projects. Industry expertise also is being tapped in CO2 projects across Europe and in Australia including four major EU proposals under the Framework Program Six and the Australian CO2CRC Otway Project. These projects address pertinent issues in CO2 capture and storage such as site selection storage monitoring and verification techniques developing local CO2 storage sites from hydrogen- and power-generation plants and industry training. In our paper framework of CO2 sequestration and vital aspects such as; site selection reservoir characterization modeling of storage and long term leakage monitoring techniques will be illustrated. Introduction The prospect of global warming is a matter of genuine public concern. The concentration of carbon dioxide in the atmosphere has been increasing since industrialization in the 19th century and consensus is forming that mankind is having a visible impact on the worlds climate. It is generally acknowledged that the most important environmental impact of fossil fuel burning is an increased global warming from the buildup of greenhouse gases in the atmosphere. This warming occurs when the added greenhouse gases trap more of the earths outgoing heat radiation. There is a wide consensus from extensive research in the last three decades that rapid climate change is already happening that global average temperatures are increasing at unprecedented rates. In parallel CO2 emissions from anthropogenic sources have also been increasing in the same time frame and these are known to produce a greenhouse effect. The greatest contributor to global warming over the past century has been carbon dioxide mostly from deforestation and fossil fuel burning. Methane is second and arises from coal deposits leaking natural gas pipelines landfills forest fires wetlands rice growing and cattle rising. Nitrous oxide also known as laughing gas is third and arises from agricultural practices fuel burning and industrial processes (Figure 1). The foremost contributor to increased atmospheric CO2 is fossil fuel combustion for power generation transport industry and domestic use. Energy from fossil fuels has provided a high standard of living in industrialized countries and the demand for energy continues to grow as developing countries seek to raise their standards of living.SCHLUMBERGERSPE108528CO2StorageCO2 Storage Geomechanics for Performance and Risk ManagementT. Brard, L. Jammes, B. Lecampion, SPE, C. Vivalda, and J. Desroches, SPE, SchlumbergerAbstract Controlling the trapping of CO2 in the subsurface i.e. storage containment is of fundamental importance for a safe geological storage of carbon dioxide. During CO2 injection increasing fluid pressure temperature variations and chemical reactions between fluids and rocks inherently affect the state of stress inside the reservoir and in its surroundings. Besides the mechanical properties of the rocks exposed to CO2 may be altered. The impact of the resulting deformations on seal integrity must therefore be assessed in order to properly manage containment performance and leakage-incurred risks. The analysis starts with the construction and the calibration of a Mechanical Earth Model of the site through joint analysis of geologic seismic logging drilling and laboratory test data. Such a model consistently describes ambient stresses fluid pressures and poro-mechanical and strength properties of the formations. It is linked to a reservoir model to achieve initial equilibrium and also to further simulate the coupled transport chemical and mechanical processes occurring during CO2 injection operations and the subsequent re-equilibration. The predicted stress path allows the evaluation of the mechanical stability of both cap-rock and faults (which may bound the reservoir penetrate the cap-rock or intercept wells). The stability of wells in formations experiencing strain is also investigated. In addition an accurate Mechanical Earth Model contributes to optimizing well construction and stimulation operations. Profiles of stresses and mechanical properties along a planned-well trajectory allow designing a drilling operation that will maximize subsequent hydraulic isolation of the well by optimizing the wellbore condition. Similar information along existing wells helps to control hydro-fracture propagation when injectivity enhancement is required. The Mechanical Earth Model can be used to develop operating envelopes for well placement hydraulic fracturing and CO2 injection that best ensure containment while achieving injectivity and capacity requirements. Introduction The climate of the Earth is warming with widespread changes in ocean salinity wind patterns precipitation and aspects of extreme weather. This is very likely forced by the increase in anthropogenic greenhouse gas concentration in the atmosphere. It is estimated that over 60% of this increase is due to carbon dioxide (CO2) emissions alone[i]. Carbon Capture and Storage (CCS) that is the capture of CO2 from industrial and energy-related sources transport and injection into the subsurface for long term sequestration purposes is a viable means to keep a significant fraction of emitted CO2 out of the atmosphere. CCS is thus recognized as a promising solution to mitigate climate change.[ii] Along with capacity and injectivity containment is agreed to be a primary function in geological storage performance. As evidenced by oil gas and even CO2 natural accumulations rock formations can be impervious enough to act as flow barriers over geological periods of time. Delineating such a seal safeguarding its integrity under operational conditions and verifying whether isolation is effective or not are key objectives in achieving a successful storage project. In particular seal integrity must not be impaired by the mechanical effects of storage operations. Indeed rocks and faults permeability may drastically increase as they undergo stress changes and deformation[iii]. The mechanical response of the sealing components to the loads induced by well drilling and completion CO2 injection and the corresponding effects on the risk of leakage must therefore be assessed when evaluating the suitability of candidate sites designing operations and planning monitoring schemes. This paper presents a methodology where characterization modeling monitoring and construction technologies are integrated for containment performance and risk management. The first section frames the performance and risk management methodology under whose umbrella the geomechanical analysis takes place. The following sections describe the building of a Mechanical Earth Model (MEM) and how mechanical modeling is coupled with fluid flow simulation so as to forecast the dynamic response of the rock mass to fluid pressure increase temperature variations and fluid/rocks chemical interactions caused by massive CO2 injection and subsequent re-equilibration. Implications in terms of risk evaluation and strategy for risk control are discussed in the last sections. Working Group I contribution to the Intergovernmental Panel on Climate Change Fourth Assessment Report The Physical Science Basis 2007. Working Group III contribution to the Intergovernmental Panel on Climate Change Fourth Assessment Report Mitigation of Climate Change Summary for Policymakers 2007. Sibson R.H.: Brittle-failure controls on maximum sustainable overpressure in different tectonic regimes AAPG Bull v. 87(6) p. 901-908 2003. SCHLUMBERGERSPE102968CO2Workshop PaperCapture/StorageCritical Issues in CO2 Capture and Storage: Findings of the SPE Advanced Technology Workshop (ATW) on Carbon SequestrationS. Imbus, Chevron Energy Technology Co.; F.M. Orr, Stanford U.; V.A. Kuuskraa, Advanced Resources Intl. Inc.; H. Kheshgi, ExxonMobil Research & Engineering Co.; K. Bennaceur, Schlumberger; N. Gupta, Battelle Memorial Inst.; A. Rigg, CO2CRC; S. Hovorka, U. of Texas; and L. Myer and S. Benson, Lawrence Berkeley LaboratoryAbstract Carbon dioxide capture and storage (CCS) is emerging as a key technology for greenhouse gas (GHG) mitigation. The Society of Petroleum Engineers (SPE) Applied Technology Workshop (ATW) on CO2 Sequestration (Galveston Island Texas Nov. 15-17 2005) convened a diverse group of geoscience engineering economics and stakeholder experts to review the status of CCS and to identify the remaining critical issues that still serve as barriers to its acceptance and widespread deployment. Site assessment can be improved with systematic generally accepted approaches that identify and focus on injection capacity and containment risks. Reservoir simulation models can be adapted from oil and gas applications but further experimental work and code development are needed to quantify the role of major CO2 trapping mechanisms. Enhanced hydrocarbon recovery accompanying injection of CO2 is well established for CO2 EOR but its efficacy in EGR and ECBM is unclear. Well integrity a key vulnerability in CO2 storage should be addressed through modified well materials and construction approaches and cost effective remediation and intervention techniques. Field management issues including risk assessment and monitoring would benefit from development of accepted practices to apply through project lifecycle. Overall the Workshop participants concluded that implementation of CCS in a timely manner represents a complex challenge that requires coordination of technical expertise economic incentives appropriate regulations and public acceptance. Storage assessment tools are available and adequate although in need of refinement and standardization. Capture technology however requires more intense research aimed at new technologies and deep cost reduction. Infrastructure and regulatory development needs to reflect expectations and incentives from government bodies. Early implementation of CCS is expected to focus on the gas processing and other industries that produce high purity CO2 with storage in local hydrocarbon reservoirs or saline aquifers. Deployment at a scale required to substantially reduce CO2 atmospheric concentrations however would rely heavily on injection into saline formations and take decades of investment to build the extensive infrastructure required to capture and transport CO2 to injection sites. The ATW gathering was a unique timely opportunity to engage experts in an assessment of the status and best path forward for CCS. Introduction Current and projected rates of CO2 emissions from fossil fuels may lead to changes in global climate with significant impact. Whereas improved energy efficiency and renewable energy will play growing roles in this century fossil fuels will continue to meet the majority of energy needs for decades to come (IEA/OECD World Energy Outlook 2004). Even with technical advances and changes in the energy mix and its efficient use there is an expanding gap over the present century between projected emissions and those emissions levels needed to stabilize atmospheric CO2 to desired levels (Edmonds et al. 2004)1. OnePetroSCHLUMBERGERSPE112259Corporate ProcessPRODMLProduction Data StandardsProduction Data Standards: The PRODML Business Case and EvolutionDave Shipley, Chevron; Ben Weltevrede, Shell International E&P B.V.; Alan Doniger, SPE, Energistics; Hans Eric Klumpen, SPE, Schlumberger; and Laurence Ormerod, SPE, Weatherford InternationalAbstract PRODML is a set of production data standards initiated by 13 upstream oil and service companies with the industry standards body Energistics (then POSC) in 2005. In November 2006 PRODML Version 1.0 was released. The focus was on production optimization processes which could produce results implementable within a day. The domain was from perforations through to start of processing on the surface. The objective was to enable plug and play integration of current upstream applications while supporting a variety of optimization processes. In 2007 the PRODML community now expanded to 23 companies worked on extensions addressing production reporting the use of a common flow network model and into smart wells. This paper authored by experienced members of the PRODML community explains the evolution from a concept to do something about production data into a well-defined series of interoperable services with a defined future path. A practical approach to the implementation of an integrated production optimization analytic environment will then be described illustrated by a richly detailed and broad-based real life case study as deployed by Chevron. The strategy that current members have set for the next three years will be outlined. This covers expansion of the footprint of PRODML (reflecting the need for a clear understanding of business drivers for end-users and for developers) functionality (supporting above all a focus on usability ensuring that PRODML expands while remaining accessible and quick to pick up for new developers) support and governance. Introduction Major energy companies embarked on innovative production technological initiatives beginning early in this decade driven by market needs for increased production coupled with increasingly challenging producing opportunities. This step change was heralded with terms such as integrated instrumented future and digital. There was no question that the changes in the world of managing production operations would require new procedures new technologies and new data solutions for acquisition processing and analysis. This situation led the founders of what became the PRODML initiative to realize an opportunity to leverage each others efforts by defining and achieving a supplier-neutral framework of standards. This framework would enable energy companies to apply their expertise to innovate and compete using commercial product solutions from vendors who in turn apply their expertise to innovate and compete. The vision is of a healthy solution marketplace with a vibrant energy company environment all geared to define how to operate and optimize production in innovative ways with greatly reduced development costs. Savings were projected for first-of-a-kind optimization solutions and even greater savings for optimization solutions adapted from previous successes.OnePetroSCHLUMBERGERSPE98945DrillingERDWorld RecordWorld-Record ERD Well Drilled From a Floating Installation in the North SeaA. Hjelle, SPE, T.G. Teige, SPE, K. Rolfsen, K.J. Hanken, SPE, and S. Hernes, SPE, Statoil, and Y. Huelvan, SchlumbergerAbstract The well 34/8-A-6 AHT2 was drilled from the Visund Field Floating Production and Drilling Unit (FPDU) in the North Sea and set on production in October 2005. The well was drilled to 9082 m/29796 ft measured depth and has an Along Hole Depth (AHD) reach of 7593 m/24911 ft which is a world record for Extended Reach Drilling (ERD) from a floating installation. The 34/8-A-6 AHT2 is also the longest Down hole Instrumentation and Control System (DIACS) installation worldwide with the lower isolation packer set at 8560 m / 28084 ft measured depth. The well includes three hydraulically operated flow valves which are used as down hole chokes to optimize the production from the separate zones in the reservoir. Subsea developments in combination with ERD wells can increase oil production and lower total development cost. The drilling progress was 108 m/day from seabed to total depth according to the Rushmore drilling performance definition and the payback time for this well was less than two months. Experiences gained on this well indicate that even longer wells can be drilled from subsea locations in the near future. Introduction The Visund field is located in block 34/8 in the North Sea 150 km west of Norway (Figure 1 2 3). The field was discovered in 1986 and production started in 1999. The Visund field is an oil & gas field with a water depth of 335 m (1100 ft). The depth of the main reservoir is between 2900-3000 mTVD with a maximum pore pressure of 434 bar. The field is 24 Km long and 4 Km wide. With this shape of the field ERD wells drilled both to the North and to the South will increase drainage area and thereby the total recovery from the field. The Visund Floating Production and Drilling Unit (FPDU) is located centrally on the field. The Visund North satellites consist of two wells tied back to the FPDU with a 9 km long subsea pipeline. The well in this case history is a world record ERD well drilled from a floating installation. In the early pre-planning phase the well was planned as a separate costly subsea development drilled by a separate semi-submersible rig. A new technical and economical study showed that this well could be drilled more economically from the existing Visund FPDU using existing subsea systems.The total depth of the well 34/8-A-6 AHT2 is 9082 m. The horizontal reach (slot to TD) is 7484 m and the along hole depth (AHD) reach is 7593 m - a world record reach from a floating installation. (Figure 4 5 6) Low friction factors in relation to torque were experienced by the use of an optimum well profile. Good hole cleaning was obtained with the use of 180 RPM on the drillstring together with maximum allowable flow rate. The ERD well has a Down hole Instrumentation and Control System (DIACS) completion with tree separate zones operated by three hydraulically controlled flow valves. This is the longest DIACS completion in the world with the lower isolation packer set at 8560 m. The well is produced at a rate of 2500 Sm/day (15700 bbl/day) with production from all zones. Production from the upper zone A would not have been possible without a controlled production from the other zones hence adding value to the DIACS completion design Experiences from this well show that even longer wells can be drilled from subsea locations in the near future. Optimal pre-planning with use of all service companies involved in detail planning and risk identification workshops are a critical factors for success. In the operational phase the work in the subsurface team was optimised through using 3D visualisation tools. These 3D tools facilitated in getting a common understanding in the whole team which was used to optimize the reservoir pay zone drilling of the well. Subsea developments in combination with ERD wells can increase oil production and lower total development cost in comparison to costly additional subsea systems that need to be installed prior to drilling a new well.SCHLUMBERGERSPE112365DrillingField Re-developmentDumbarton FieldDumbarton Field, UKCS: Rapid Redevelopment of a Complex, Mature North Sea Asset Using New Rotary-Steerable and Geosteering TechnologiesUkpe John, SPE, Schlumberger; Ian Tribe, SPE, Schlumberger; Jim Manson, SPE, MaerskOil UK; Andy Stewart, SPE, MaerskOil UK; Martin Pendlebury, SPE, MaerskOil UK; Emily Ferguson, SPE, MaerskOil UK; Kenneth Melvill, SPE, Schlumberger; Daniel Bourgeois, SPE, Schlumberger; and Rebecca Lepp, SPE, SchlumbergerAbstract The Dumbarton Field operated by Maersk Oil North Sea in Block 15/20 has a number of drilling and well placement challenges which hampered development during the 80s and 90s when operated by the previous owner. These include formation instability directional-drilling control issues and thin complex reservoirs which are poorly imaged on seismic. Reservoir overburden is fast drilling formations with hard stringers. The field pore-pressure gradient is at 9.07ppg EMW but mud density needed for wellbore stability is greater than 11.6ppg. This resultant high overbalance and other issues such as hole cleaning complex directional profile ECD management at high ROPs can lead to inefficient motor drilling. The soft formations also create limitations for push-the-bit rotary steerable systems to deliver the required directional performance to land wells. To overcome these drilling challenges a new point-the-bit rotary steerable system with a high dogleg capability has been utilised for successful landing of these wells into reservoir sections without need for pilot holes or mechanical sidetracks. Additionally a new LWD tool that allows monitoring of the distance and direction to formation boundaries up to 15 ft away from the wellbore has been used to proactively guide the wells along the thin oil reservoir units/sands. These tools also enabled the wells to be placed as close to the reservoir roof shales as possible to maximize stand-off from the waterleg and hence increase overall oil recovery. Distance and direction to boundary data displays are intuitive to interpretation allowing better geosteering decisions without compromising ROP and drilling efficiency. Within six months six wells were delivered including three sidetracks (One top hole and two horizontal sections). All wells penetrated more reservoir sand than prognosed and all were drilled faster than prognosed. Initial production testing was higher than expectation. Introduction This paper uses a case study to highlight the benefits of using Point the bit RSS the latest LWD tool technologies and process for redevelopment of an otherwise impossible matured field. The case is the Dumbarton development project which is a redevelopement of the BP Donan field by Maersk Oil UK. The filed was discovered by 15/20a-4 well in 1987 and appraised by a 15/20a-6 well (a deviated well drilled from the 15/20a-4 surface loacation) in 1990. Production from these two wells commence in 1992 untill 1997; at this point a total of 15.3 mmstb oil was produced. In 1995 there was a planned Phase 2 development consisting of replacing the two producers which were becoming increasing wet with a drier horizontal wells to be drilled to the west of 15/20a-6 well. Five attempts (wells 15/20b-12 12Z 12Y 12X 1W) were made but all were understood to have been considered at that time to be disappointing. The previous operator then decided to abandon any further development enhancements and to continue producing the existing wells until it ceased to be profitable. As a result the field was abandoned in 1997 at this point the final water cut was 71%.SCHLUMBERGERSPE119506DrillingHorizontal WellLongest in WorldHow Continuous Improvement Lead to the Longest Horizontal Well in the WorldKumud Sonowal and Bjarne Bennetzen, Maersk Oil Qatar AS; Patrick Wong, K&M Technology Group; and Erhan Isevcan, Schlumberger D&MAbstract Maersk Oil Qatar AS (MOQ) completed drilling the world record BD-04A well in May 2008 offshore Qatar. This was the successful outcome of engineering efforts to increase extended reach capabilities. MOQ started to develop the Al Shaheen Field offshore Qatar in 1994 with the application of horizontal drilling techniques pioneered by Maersk Oil & Gas AS in the North Sea. In 1994 10 220 feet was the longest horizontal length drilled by MOQ. In May 2008 the BD-04A well was completed with a record horizontal length of 35 770 feet. This well also set new world records for both the longest well at 40 320 feet MDRT and the longest along hole departure of 37 956 feet. The introduction of new techniques has allowed existing constraints to be successfully challenged and overcome. This was achieved through the application of sound engineering principles and continuous optimization during the field development phases. This case study will review the history challenges and planning leading through to the successful drilling of the BD-04A well. The paper will outline the achievements improved practices and the engineering analysis of field data where key learning points have been shared for future use and applications. It will show that even when constrained by certain limitations such as rig capacity major step changes can be achieved by optimizing basic operating parameters. In addition to the world record several other accomplishments have also been achieved in this well as detailed in this paper by using state-of-the-art horizontal drilling technology. The paper will not only contribute directly to the industrys knowledge base related to improving hydro carbon recovery through extended reach horizontal wells but also set an example of how operating envelopes can be extended by continuously challenging existing practices. Introduction MOQ operates the Al-Shaheen Field Block 5 under a production sharing agreement with Qatar Petroleum (QP) on behalf of the State of Qatar - an area of originally 3 500 square kilometres offshore Qatar which is located on the central axis of the Qatar Arch some 80 kilometers north-east of the Qatar peninsula (Figure 1) . The exploration and exploitation rights include all Block 5 geological formations above the Khuff formation. The main targets comprises of (from bottom to top) the Lower Cretaceous Kharaib B and Shuaiba carbonate formations and the Nahr Umr sandstone (Figure 2). The Kharaib Formation is a laterally uniform carbonate deposition. The thickness of the Kharaib is generally 80 feet with a reservoir target of some 25 feet. The Shuaiba Formation exhibits lateral facies changes and permeability contrasts. Its thickness is generally 200 feet with a reservoir target of some 20 feet. The Nahr Umr Formation is a 20 foot sand sequence with reservoir targets of some 5 feet or less of permeable sand.OnePetroSCHLUMBERGERSPE113843EOR/IORCO2 InjectionEOR Potential of the Michigan Silurian Reefs Using CO2Brian Toelle and Larry Pekot, Schlumberger Data & Consulting Services, and David Barnes, Mike Grammer, and William Harrison, Western Michigan UniversityAbstract The Guelph Formation historically known as the Brown Niagaran is a Silurian age formation in the Michigan Basin containing hundreds of pinnacle reefs. These reefs discovered primarily during the 1970s have produced nearly half a billion barrels of primary oil. Over 700 reefs make up the northern trend and more than 300 reefs have been located in the southern portion of the basin many of which have produced more than 5 MM bbls of oil. The EOR potential of these fields is believed to be significant. Few of these fields have been waterflooded and only five have experienced CO2 injection. An ongoing US Department of Energy project is studying the use of CO2 in enhanced oil recovery operations at the Charlton 30/31 reef which is located in Michigans Otsego County. This field was discovered in 1974 by Shell and produced 2.6 million bbls of oil during its primary production phase from a reservoir that may be typical of the other reefs in these trends. The reservoir is composed of a limestone matrix with low porosity and low permeability that contains irregular dolomitized intervals. These dolomitized zones with higher porosity and permeability control the flow of fluids through these reservoirs. This project utilized 4D seismic reservoir simulation and a new well drilled into the reef to provide greater understanding of the CO2 EOR potential for this and all of the Silurian reefs in Michigan. Introduction Recently the price oil broke $100 per barrel for the first time. The increase in oil price seen in the last few years has refocused attention on oil productive reservoirs. This is particularly true within the US where the transportation costs associated with delivering the product to the point-of-sale is significantly less than imported products. Due to the decrease in exploration activity brought about by the low prices of the preceding decades few new oil fields have been located within the US. Many existing fields are older and these have significant potential for enhanced oil recovery. One producing area that could benefit considerably from EOR techniques is the Silurian reef trends of the Michigan Basin Figure 1. These reefs occur in the Guelph Formation which is a stratigraphic unit that has historically been referred to as the Brown Niagaran. The first large commercial scale Niagaran reef field was the Boyd Field in St. Clair County. Discovered in 1952 the Boyd has produced over 2 MM bbls of oil and over 21 BCF of gas. From the mid 1940s through the 1960s a number of publications addressed the regional stratigraphy and paleogeography of the Silurian in the Michigan and Illinois Basins. An early lithofacies analysis of the areas Silurian was conducted by Melhorn (1958). The paleontology petrography and geometry of northeast Illinois Silurian reefs were described by Ingels (1963). Joudry (1969) published research on potential dolomitization mechanisms in the Southern Michigan Basin Reef Trend. In 1969 the first field in the Northern Silurian Reef Trend was discovered leading to additional investigations of these reefs.These included works by Mesolello (1974) Shaver (1974) and (1977) Huh (1976) and Nurmi (1977). One of the more prolific workers on these structures during this time was Gill (1973 1975 1977 and 1979). In 1987 Cercone and Lohmann discussed diagenesis in these reefs.SCHLUMBERGERSPE107445EOR/IORCO2 SourceQuebrache--A Natural CO2 Reservoir: A New Source for EOR Projects in MexicoHeron Gachuz Muro, Sergio Berumen Campos, and Luis O. Alcazar Cancino, Pemex E&P, and Jos A. Rodrguez Pimentel, SchlumbergerAbstract CO2 injection is one of the most efficient methods used to improve oil recovery and as world statistics shows its use has increased recently. Under a high crude oil price scenario field applications of enhanced oil recovery (EOR) processes are becoming economic in todays environment. The natural CO2 sources come to be an excellent opportunity because of its low cost. Since 60 years ago 2500 km2 of carbonate formations containing CO2 were discovered in North of Mexico. The Quebrache region contains several occurrences of natural CO2 that have been discovered during exploration of oil fields. The CO2 that has been naturally trapped in carbonate formations in this region is present in concentrations that can exceed 90% purity. Due to the high concentrations of CO2 some wells were shut-in 60 years ago others have been developed for CO2 production intended for industrial uses and some others as a source of gas lift operations in nearby heavy oil fields. Recently a plan of acquisition of information and studies to evaluate the CO2 proven reserves has been designed. In addition analysis of wells deliverability of these natural CO2 reservoirs located in the southwestern portion of Tampico has been carried out. In order to understand better this field a geological model was built and its dynamic behavior and potential was examined through several well tests. Results of the interpretation of these tests showed excellent results associated with a reservoir of good permeability high conductivity large drainage radius etc. According to the geology of this region and the geochemical signatures observed the CO2 of Quebrache field has an inorganic origin. This paper discusses the evaluation of potential supply of CO2 of Quebrache reservoirs for EOR projects in the North of Mexico. The main region studied contains estimated proven reserves of 1.9 Tscf of CO2; however this volume could be extended to larger amounts associated to areas under study. The CO2 from Quebrache field could be the beginning of a new era of EOR projects in Mexico. A field example of potential EOR application in a mature oil field is shown. Introduction Quebrache Region contains numerous occurrences of natural CO2 that have been discovered during exploration of oil fields. Most CO2 fields are similar to conventional natural gas fields with the gas trapped in dome-like structures. The most common reservoir lithologies are sandstones and dolomite with mudstone and anhydrite being the most common sealing rocks. Carbon dioxide occurs naturally as a result of geologic processes in large often high-purity (>90 %) deposits in many sedimentary basins. Several CO2 fields in the United States Hungary Turkey and Romania have been or are being developed to provide an efficient source for enhanced oil recovery projects. On average the global risk of encountering >1% concentrations of CO2 in a gas reservoirs is < 1 in 10 and the risk of encountering >20% concentrations of CO2 is < 1 in 100. However here is the issue: the mean CO2 content of reservoirs with >20% CO2 is 50% CO2. In other words when CO2 is abundant it is frequently so abundant. Furthermore high CO2 concentrations are encountered in diverse areas. The scientific study of natural CO2 deposits is still at an early phase. Previous work has included documentation of worldwide occurrences of natural CO2 deposits and preliminary assessment of commercial CO2 fields in the USA. This paper discusses the results of the first study oriented to evaluate the CO2 proven reserves of Quebrache field and its potential application as EOR project in a mature field in the North of Mexico.SCHLUMBERGERSPE99720EOR/IORHeterogeneityOligocene Vicksburg FormationOligocene Vicksburg Thin-Bed Production Optimization Derived From Oil-Based Mud Imaging: A Case StudyD.L. Fairhurst, B.W. Reynolds, S. Indriati, and M.D. Morris, SPE, Schlumberger, and E.G. Hanson, Abaco Operating LLCAbstract The Oligocene Vicksburg formation in South Texas has been a prolific play for many years with targets of thick and stacked sand bodies. These thick sections have been primarily exploited and produced. Still existing are many previously considered uneconomical sequences. These marginal sections consist of highly laminated sand shale sequences along with disbursed clay in sand. Standard cutoffs from basic log evaluation work correctly for the disbursed clay sections. But the cutoffs are inadequate for the highly laminated sequences; many thin high-quality sands have been overlooked. These sections can now be discerned using microresistivity measurements in oil-based mud systems and new high-resolution cutoffs can be employed. A production prediction model is critical to enhance the chance of success. The model used here employs a petrophysically consistent high-resolution permeability estimate fracture geometry prediction and formation pressure. The methodology identified several sands as commercial that have been bypassed in offsets with the old cutoffs. Over a two-year drilling program data gathered from several field example wells were analyzed. These are presented here to illustrate how production data was utilized to continuously adjust and calibrate the high-resolution petrophysical model. The incremental revenue from the added pay exceeded the cost of this new methodology and enhanced the economic viability of the field. This integrated process of measurement analysis prediction evaluation and model adjustment enables the operator in South Texas to make timely completion decisions as well as set-pipe decisions. This process is becoming a useful tool for further exploitation of the mature Oligocene Vicksburg formation of South Texas. Introduction The Vicksburg formation in South Texas has been exploited since the 1920s and is still a prolific producer with over 20 Bcf per year average rate (Fig. 1). The play has seen both productivity increases and declines depending on gas prices and technology drivers. Since the mid-1990s however the trend has been ever-decreasing productivity and faster rate declines. At the same time only 12% of the estimated 3 860 Bcf ultimate recoverable designated tight gas in Vicksburg has been produced [1] leaving much to be recovered. Some of this recovery can be enhanced with recently developed high-resolution technology. The decision on whether to set pipe or complete a particular zone usually is made once the logging run is complete.During the standard logging run the analyst will view the density porosity output and question the economics. What is the porosity cutoff to make a well here? The answer is found over years of experience and the school of hard knocks. Typically a Rule of Thumb is used and a line is drawn (Fig. 2). Many South Texas partners make their decisions based on these cutoffs and individual experience. Worthington gives a comprehensive perspective on the use of these cutoffs.[2] The cutoff number most often used in the Oligocene Vicksburg trend of South Texas is 15-16% porosity (Fig. 2). More recently there has been success at much lower porosity in the range of 8-10%.[3] Obviously if a 16% porosity cutoff was applied routinely then somewhere in the thousands of wells drilled some pay has been bypassed. One solution that has been used primarily in water-based systems has been laminated sand analysis. This type of analysis has been applied since the early 1990s primarily in turbidite plays[4] and not verified with production. The analysis used here verified with production data provides a better answer for the less obvious and often bypassed pay sands.SCHLUMBERGERSPE98142EOR/IORMultilateral SidetracksGas CondensateSimulation Study of Re-Entry Drilling for Gas/Condensate Reservoir DevelopmentS. Luo, SPE, Schlumberger, and M.A. Barrufet, SPE, Texas A&M U.Abstract Gas-condensate reservoirs usually exhibit complex flow behavior due to the near-wellbore condensate bank build-up when bottomhole pressure drops below the dew point.Such an accumulation of condensate liquid in the near-wellbore region forms a ring that may significantly reduce the gas relative permeability and consequently the well productivity.Also when reservoir pressure drops below the dew point a big portion of condensate liquid will remain in the reservoir and will not be produced. Many condensate reservoirs have been producing with vertical wells.This paper presents a practical strategy of rejuvenating gas-condensate reservoir production through multilateral sidetrack reentry drilling technology. Simulation studies show that reentry drilling through vertical wells can help break the condensate bank damage and significantly increase well productivity. Sensitivity analysis of fluid type reservoir permeability lateral length and reentry drilling time on production performance is conducted.Results show that multilateral reentry drilling represents a very promising technology for developing medium/low permeability gas-condensate reservoirs. Introduction Gas-condensate fields have significant industry importance.The profitability of gas-condensate field development depends on both gas and condensate production profiles. Two major reservoir engineering problems associated with gas-condensate reservoir development are: (1) possible drastic drop in gas productivity when pressure drops below dew point pressure (2) loss of condensate trapped throughout the reservoir at the end of exploitation.The loss of productivity in gas-condensate reservoirs due to near wellbore condensate dropout is well discussed in the literature.[1 2 3 4] Reentering wells to gain additional production is not new.Since the mid-1950s oil companies have reentered old wells and drilled sidetracks to bypass formation damage or wellbore mechanical problems and to exploit new zones saving the cost of drilling entirely new wells.[5 6] In this study we proposed a practical strategy for rejuvenating vertical well production of gas-condensate reservoirs under depletion through reentry drilling of multilateral branches from existing vertical wells to bypass the condensate bank zones. Comprehensive simulation studies using industry-standard reservoir simulator ECLIPSE (trade mark of Schlumberger) were conducted to investigate the potential of this technology in different reservoirs.Sensitivity analysis was also done to evaluate the effect of fluid type reservoir permeability lateral length and reentry drilling time on production performance.Results show that this technology will be very promising for application in medium/low permeability gas-condensate reservoirs. For actual field implementation a more detailed reservoir simulation study with proper geological description and project economic analysis should be conducted to guide the successful design and application of this technology. Simulation Model and Parameters A 3-D model of a hypothetic field is used in this study.The field is produced by natural depletion without considering any pressure maintenance. The simulation model and parameters are described as follows.SCHLUMBERGERSPE117622EOR/IORSAGD OptimisationEasterm VenezuelaApplicability and Optimization of SAGD in Eastern Venezuela ReservoirsJos Antonio Pia R., Jos Luis Bashbush, Edgar Alexander Fernandez, SchlumbergerAbstract The work presented in this paper describes the evaluation and stepwise optimization process for a Steam-Assisted Gravity Drainage (SAGD) project using a representative sector model from a field with fluid and reservoir characteristics from an eastern Venezuela formation. Due to the complexity and number of variables involved in the process SAGD presents multiple challenges from the design and analysis phases to its final implementation. The objective of this investigation was to understand the impact of key parameters in the process specific to the selected area and to understand the effects on the recovery factor in these reservoirs which have previously produced with primary recovery mechanisms. The study touches upon the effect of the component grouping for fluid characterization. A preliminary work consisted of reducing the original 14 components identified in the existing Pressure/Volume/Temperature (PVT) analysis into 2 and 3 pseudocomponents and comparing the stability and results using both fluid characterizations to attain reasonable running times in the simulation process. Once the fluid behavior was successfully recreated and the model was set up a sensitivity analysis was conducted using thermal simulation. The parameters analyzed were vertical well spacing injection steam rate well flowing pressure and horizontal length of the well pair. The effect on the oil recovery from the angle of dip in the reservoir and the orientation of the well pair with regard to the direction of dip were also briefly analyzed. The conclusion presents a highly improved configuration for the SAGD well-pair array that resulted in trebling the oil recovery attained by the initial well arrangement. Introduction The SAGD process has been considered from the beginning of the thermal Enhanced Oil Recovery (EOR) applications as one of the most effective recovery methods based on the ever present gravitational segregation effects using steam injection and the favorable reduction in oil viscosities within the reservoir. It has been reported that recovery factors could reach up to 60% in the areas impacted by the steam. Several SAGD projects have been applied in Canada demonstrating the efficiency of SAGD for bitumen accumulations. Based on this experience many oil companies have taken this technology as their main technique to be applied in the field to exploit the heavy and extra-heavy oil accumulations. In Venezuela a considerable amount of heavy oil in place has been mapped but to date limited areas have been developed. Because of the nature of oil contained in these accumulations and their in situ viscosities natural production mechanisms will render low recoveries. Therefore suitable EOR methods need to be applied to extend the productive life of these reservoirs and increase their recovery factors.SCHLUMBERGERSPE112021EOR/IORWell InterventionGas Shut-offChallenging Chemical Gas Shut Off In a Fractured Carbonate ReservoirCase StudiesHamed Al-Sharji, Ali Ehtesham, Bela Kosztin, and Clement Edwards, PDO; Fardin Ali Neyaei, and Tarek Shaheen, SchlumbergerAbstract This paper discusses the gas shut-off treatments carried out in a fractured carbonate field in north Oman and also describes the good practices and lessons learnt from a number of jobs. In addition to the technical analysis the paper also addresses the economic value of the campaign. Oil production from this field with complex geology and reservoir mechanism was negatively affected by gas breakthroughs in several wells. The constraints on gas handling capacity resulted in shutting-in a number of high GOR wells. These wells were required to be treated to shut-off source of the gas breakthrough in order to restore oil production. Challenges faced in shutting off these gas zones included: 1) Poor cement bond behind the liner shoe. 2) Massive fractures resulting in loss circulation. 3) Uncertainty with fractures volume estimation. 4) Fracture shut-off in open-hole sections. 5) Treatment execution under sub-hydrostatic conditions. To overcome these challenges a robust chemical shut off methodology had to be innovated. This methodology consisted of the following main pillars: a) Utilize various reservoir diagnostics tools to identify fractures and sources of high GOR. b) Use of flowing cross-linked polymer gel combined with a ringing type of cross-linked polymer gel as a capping fluid. c) Utilize an on-fly mixing system that enables volume and concentration adjustment as plugging progression dictates. d) Utilize matrix diagnostics plot along with modified hall plot in real-time to continually estimate flowing gel volume. e) Deploy a fit-for-purpose gel placement assembly for treatment under Sub-hydrostatic conditions. Introduction The giant fractured carbonate field was discovered in 1964 and came on stream three years later. The field has 7 reservoir layers (A to G) and multiple subunits within each layer. The upper layers A B C D and E1/E2 are more intensely fractured than lower layers E3/E4 F and G reservoirs. Initial production from the reservoirs (1967 to 1970) was by natural depletion supported by gas injection in the A reservoir unit starting 1968. After this initial period of gas injection water injection was implemented in the A C D and E reservoirs (1970 to 1984). Previously unknown fracture networks in these layers resulted in rapid water breakthrough. This was followed by GOGD (Gas-Oil-Gravity-Drainage) development (1984 to 1998) which was successful in arresting the decline in the oil production. Following a simulation study in 1996 it was decided to implement a line-drive waterflood with horizontal wells in those layers considered to be sparsely fractured. Because GOGD is not effective in sparsely fractured reservoir water flooding those layers was expected to substantially increase recovery in those layers. Since 1997 field development and operation has utilized this combination of GOGD and localized waterflood1.SCHLUMBERGERSPE123773EOR/IORWell InterventionUndeveloped ReservoirsRecovery of Bypassed Reserves Above Top Packer Using Innovative Cement Packer and Through Tubing Add PerforationWong Chun Seng and Suhaila Wahib, Petronas Carigali; Choo Der Jiun andRonald Ramnarine, BJ Services Malaysia; and Mohd Shafie Jumaat, Schlumberger MalaysiaAbstract West Lutong is a mature field with 8 rounds of field development campaigns and close to 40 years of production. Currently only 50% of total strings are flowing. However the idle wells could possibly access undeveloped marginal reserves in shallow reservoirs. These shallow reserves are located above top production packer as they were not previously included in initial completion due to historical sand problem Following West Lutong Full Field Review in 2006 presence of by passed potential reserves above top production packer were confirmed. Conventional workover rig to re-complete these potentials is not economically viable due to significant cost and complexity. An innovative rigless cement packer approach had been chosen for the pilot job in Well # A while retaining necessary level of completion integrity .The proper placement of cement packer approach involves usage of hydrostatic sequence valve as choke manifold to prevent U tube effect. Numerous down hole problems such as wax scale sand and fish from insert string had been rectified using appropriate coiled tubing solutions. Conventional E-line perforation using high density shot gun and deep penetrating charges were then used. Well # A had been producing under controlled condition average 930 bopd without sand problem for 10 months since July 2008 with 1.10 MMstb reserves monetized.The total cost was only 10% of a conventional workover. This paper shares a detailed case study of Well # A in term of candidates selection reserves estimation cement packer execution lessons learnt and future recommendations. It is evident that cement packer technology is feasible and economic for accessing by passed reserves above existing production packer. Introduction The West Lutong field was discovered by well WL-01 in 1966 and brought on production in mid 1968. It is located offshore Sarawak approximately 13Km North West (NW) of Miri in water depth of 70 -100 ft. The first discovery well was drilled in 1966 and a total of 4 additional wells were drilled thereafter to appraise the structure. Production started in 1968 from the four exploration/appraisal wells. Subsequently there have been a total of 8 drilling/workover campaigns as depicted in Figure 1. Currently only 50% of total strings are flowing .However the idle wells could possibly access undeveloped marginal reserves in shallow reservoirs. The West Lutong reservoirs were deposited some 20-23 million years ago during Cycle V of the late Miocene in a lower coastal plain to coastal environment. Shore face deposits dominate the sequence which also includes some channels and associated bar forms. Reservoir sands are loosely consolidated fine to very fine and inter-bedded with layers of silts and clays. Average reservoir porosity ranges from 14 to 26 % with a field wide mean of 20% permeabilities are in the order of 50 to 300 mD average net-to-gross is 0.62 and net sand thickness is generally less than 30 ft with most sands around 10 ft thick.OnePetroSCHLUMBERGERSPE103329EOR/IORWell InterventionWater Shut-offProduction Improvement Water Shut-Off for White Tiger FieldKeng Seng Chan, Schlumberger Well Services; Duong Danh Lam and Aleksey Ivanov, VietSovPetrol; Kiam P. Apisitsareekul, Schlumberger Well Services; Le Viet Hai, VietSovPetrol; Nguyen Chinh Nghi, Schlumberger Well Services; and Vuong Quoc Hung and Le Dinh Lang, VietSovPetrolAbstract Oil production from some of wells in the White Tiger field producing from a fissured Basement reservoir; have been impaired by excessive water production. Excess water not only reduced the artificial lift efficiency but also imposed various damages to the oil zones. Since 2002 a joint industrial project was set up to study the feasibility of performing water shutoff treatments in the open-hole completion oil wells. The study involved evaluation of a high temperature polymer base water shut-off fluid for deep penetration of the fissure formation and a micro-fine cement system for sealing off the water entries. Based on this study a cost-effective chemical treatment method was progressively developed. In 2005 the treatments were performed through-tubing with and without isolation packers. Two Candidate wells were having 6.5 open-hole size at approximately 4 200 meter TD and 150 deg C reservoir temperature. The water cut were 95% in one well and 30% in the other well. It was found that these two wells certainly had big difference in fluid injectivity and original designed treatment was modified on site. This paper summarizes key lessons learnt including tool and packer conveyance mixing and pumping of water shut-off fluids under offshore rig and wellsite conditions. It also shares a method of post treatment production evaluation and suggests operational change to improve the production. Introduction White Tiger Field in offshore Vietnam is producing from a highly fissured granite Basement formation. Basement consists of igneous crystalline rocks characterized by petrography heterogeneity because they were formed in different tectonic activities in their geological evolution. Since being formed to recent the basement rocks of the Cuulong basin have been strongly affected by different alteration processes. These processes changed not only the composition petrophysical characteristics but also were principal causes creating good reservoir properties of some granitoid basement bodies. Some main alteration processes are volume shrinkage due to the crystallization of magma lavas alteration due to the tectonic activities alteration due to the hydrothermal activities alteration due to the weathering activities. The inside volume of magma bodies is often shrank when the magma lavas crystallized and solidified. This volume shrinkage caused by sudden change of temperature as well as by viscosity increase during the times that these magma lavas crystallized and resulting in the formation of individual micro fractures and misco-vugs in granitoid rocks. These micro-pore types can be only beneficial for reservoir if they had linked together by fractures and microfractures which were formed due to tectonic activities at later times. The tectonic activities are principally factors making strong and widespread alteration of basement rocks. The basement rocks have been fractured broken and catalazited at various degrees developing different fracturing systems with different directions. The fracturing and breaking did not change the rock composition but they strongly altered the structure texture and particularly the petrophysical characteristics of the basement rocks. The petrophysics characteristics of altered basement rocks in the White Tiger (Bach Ho) field change very strongly both with depth and area. Permeability ranges from less than 1mD to hundreds mD. Two principal porosity types that are fractured/micro-fractured and cavernous/micro-cavernous pores can always be observed in the altered granitoid rocks (figure 1)."SCHLUMBERGERSPE104755EOR/IORWell InterventionWater Shut-offCase Study in Water Shutoff Fluid Placement Using Straddled Through-Tubing Inflatable-Packers TechniqueRedha Kelkouli, SPE, and Maen Razouqi, SPE, Schlumberger, and Saeed Al-Shaheen, Abdul Rasool Al-Khamees, and Abdulaziz Abdulla Dashti, Kuwait Oil Co.Abstract Most of the wells in Sabriya Field (Northern Kuwait) produce from reservoirs where multiple layers are opened to production. Problems related to non-desired water production are drastically affecting the oil production and have been an ongoing concern. The exclusion of this water represents a challenging task by itself especially in case of multiple zones interval simultaneously producing and where completion of the wells restricts considerably the convoyed down-hole tools configuration This paper covers water shut off case history of an oil producer that has shown according to the production data an increasing water production figures. The nature of water problem and the fact that the targeted section is located in-between multiple oil producer zones revealed the necessity of a complex thru tubing zonal isolation solution before performing the water shut-off treatment. Temporary coiled tubing conveyed straddle system was created using two thru tubing inflatable packers isolating the top and bottom perforated zones in order to provide both proper zonal isolation and accurate treatment placement. The post water shut off treatment showed up to 70% water flow reduction from the targeted layer has been achieved. Introduction Fulfilling requirement such as limited outside diameter (OD) due to the production tubing restrictions or high expansion ratio conformance due to the large inside diameter (ID) of the producing casing through tubing inflatable packers (TTIP) technology conveyed with Coiled Tubing has evolved to the point to become an established alternative for the oilfield operators proving to be capable of effective zonal isolation on a broad range of applications (multiple zones stimulation water/gas shut off zonal production evaluationetc) where accurate selective fluid placement is essential for the success of the job. However the biggest challenge remains the nonproductive time due to the tools reliability especially in harsh HPHT (high-pressure high temperature) environment and challenging well-bores configuration (High inflation ratioetc). The recently developed TTIP systems are specifically designed to perform reliable zonal isolation in HPHT environment high inflation ratio applications with enhanced differential pressure capabilities through technological advanced component design. The complicated nature of the water problem in northern Kuwait because of the fact that the targeted sections are usually located in-between multiple oil producer zones revealed the necessity of a complex zonal isolation solution before performing the water shut-off treatment. An oil producer that has shown -according to the recent production data - an increasing water production figures was identified as a good candidate for such approach. A temporary straddle system was created using two through tubing inflatable packers therefore isolating the top and bottom perforated zones in order to provide both proper zonal isolation and accurate treatment placement. TTIP Technology Overview The TTIP is run in the well on the end of coiled tubing to the required depth and then inflated depending on the type of the application being performed and once the desired treatment is pumped the packer is either deflated and retrieved or the running tools are disconnected from the TTIP and the coiled tubing string is pulled out of the well. HPHT TTI packers enables permanent abandonment of zones in addition to temporary wellbore areas isolation for tubing integrity tests and general pressure testing (Wellhead production tubingetc) as well as selective acid stimulation and water/ gas control treatments. Typically Two TTIP applications can be distinguished: Testing & Evaluation (Temporary Isolation) The zonal isolation in this case enable the selective evaluation of intervals production benefit this is typically the case in wells where its felt that one zone is affecting the production (High GOR or high water cut). This zone once isolated the well can be either flowed and the production tested or submitted to injectivity step rate test and therefore estimate the impact of stimulating or permanently shutting-off the lower zone (Figure 1).SCHLUMBERGERSPE107101EOR/IORWell InterventionWater Shut-offWater-Shutoff Treatment in Wells With Single-String Multizone Completion Intervals (Brownfields)Victor E. Uadiale, Schlumberger; Otaru G.Oghie, Shell E&P, U.K.; and Vincent O. Nwabueze, Shell E&P, NigeriaAbstract Due to the stacked nature of reservoirs in the Niger Delta the predominant completion types are dual-string multizone and single-string multi-zone completions. These designs have been adopted to reduce the number of infill wells required for field development. However they come with a disadvantage in regard to carrying out a successful intervention when water break through occurs. Water breakthrough and high basic sediments and water (BS&W) are problems associated with fields having strong aquifer drive mechanisms. As a result most exploration and production companies have learned to manage water production up to a tolerable limit which is dependent on the water handling capacity of the installed facilities and also the economic cutoff limits for the wells in question. The reason for this type of water management is the lack of confidence in the water shutoff remedial operations. From a survey carried out in the early 90s it was estimated that only 35% success was achieved worldwide in water shutoff remediation. This low success rate is due to poor diagnosis wrong selection of water shutoff solutions and how complicated the well completion is with respect to the zone of interest to be treated. Field X 1 2 which consists of a large gas cap and a 100-ft total vertical depth (TVD) oil column was developed with the single-string multizone completion design. Due to the presence of a strong aquifer in this field water production started early and some of the wells were shut-in due to lift problems associated with the water production. A sidetrack option was considered as a means of bringing these wells back on production but was not used because of the absence of a gas gathering facility for the field. As a result of production decline and lack of infill opportunities cement-water shutoff and re-perforation intervention in the wells was adopted. The objective of the cement-water shutoff was to ensure that the perforations which were flushed were completely sealed off and isolated and subsequently re-perforated shallower. After slurry placement and squeezing it is important to ensure that a good cement job has been performed. Operationally the top of cement (TOC) is tagged using slick-line in a vertical or deviated well. If the TOC is not at the theoretical depth then a top-up job is carried out with additional slurry. On the other hand if the TOC is at the theoretical depth then a pressure test is performed to confirm that the perforations are squeezed off. For intervals behind the sleeve as in the case of Field X ascertaining the TOC is technically impossible because the perforations are behind the production tubing. For such single-string selective completions only a pressure test can be performed to confirm that the perforations are squeezed off. This paper addresses the planning operational and the learning from the through-tubing water shutoff campaign successfully carried out on wells with single-string multizone completions. Introduction Cement-water shutoff intervention behind the sleeve in multizone completions is a solution that is not common due to its low probability of success. Shell Petroleum Development Company Nigeria and Schlumberger successfully carried out this operation in four wells drilled and completed in Field X. The biggest issue associated with cement squeeze in a singlestring multizone completion is the difficulty associated with placement and confirming where the TOC would be after the intervention. This by implication makes it difficult to determine if a good cement job has been performed.SCHLUMBERGERSPE110968EOR/IORWell InterventionWater Shut-offSuccessful Water Shut-off in Open Hole Horizontal Well Using InflatablesFaisal F. Al-Shahrani, Zulfiqar A. Baluch, Nashi M. Al-Otaibi, Saudi Aramco, and Tashfeen Sarfraz, SchlumbergerAbstract Water shut-off treatment (WSOT) using through tubing bridge plug (TTBP) in open hole completion has been employed for the first time in a dead horizontal well in one of the onshore fields in Saudi Arabia. It was successfully applied by setting an inflatable bridge plug (TTBP) in the 6 1/8 open hole at 10 600 ft at 88 and capping it with cement and gel using coiled tubing (CT). Historically it has been difficult if not possible to perform mechanical water shut-off in open horizontal well as inflatables are quite sensitive to be set in open hole. This paper shows that this type of water shut-off in open hole is feasilble and very effective. This will open the doors to apply similar techniques to liven dead horizontal wells in other fields. Introduction Excess water production in oil well is always a cause of concern. There are many side effects of this bad water production: It adds to oil production cost by way of increased lifting separation and disposal cost. It leads to scaling in wellbore tubing flow lines and processing facilities. It also leads to corrosion and degradation of completion and flow lines. It imparts higher hydrostatic pressure on the formation as water is heavier than oil thus reducing the pressure available for carrying oil to the surface. In many cases high water production from the formation results in dead wells. All these concerns make the water shut-off a matter of high importance and concern. There are several techniques being used to reduce or eliminate water production: 1. Chemical techniques like resins epoxies polymer gels etc. to plug the water producing features. 2. Using bridge plugs cement plugs and other mechanical devices to stop water production. Definition of problem The well was completed as an S shape open hole producer with approximately 2675 ft of reservoir contact. Out of this 1600 ft was placed horizontally at the top 50 ft reservoir while the remaining footage was drilled slanted across the same reservoir for evaluation purposes (Fig. 1).SCHLUMBERGERSPE111512EOR/IORWell InterventionWater Shut-offInnovative Water-Shutoff Solution Enhances Oil Recovery From a West Venezuela Sandstone ReservoirGoran Andersson, SPE, PetroBoscan; Gregg Molesworth, SPE, Chevron Technology Company; and Belkis Gonzlez, Salah Al-Harthy, and Eric Lian, SPE, SchlumbergerAbstract With the discovery of new fields becoming less common and the continued development of brownfields water control is becoming increasingly essential to enhancing oil recovery. Water control operations are especially challenging in under-pressured reservoirs with openhole completions such as in the Boscan field in West Venezuela. Gravel-packed slotted liners and standalone premium screens are common completion methods in this field. Dual injection combined with permanent water shutoff (WSO) gels or relative permeability modifiers to control water production in these completions has traditionally produced inconsistent results. This method can fail to change the well production profile and possibly damage oil-producing layers. This paper will discuss the development implementation and results of an innovative solution for water shutoff that was engineered for the complex completion methods mentioned. The solution involves three key stages; the temporary isolation of the producing layers the permanent shutoff of the water zones and the effective cleanu