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

ChevronOrganisationSourcePaper No.ChapterSectionSubjectTitleAuthorAbstractCHEVRONSPE98583CO2Capture/StorageCarbon Dioxide Capture and Geological Storage: Contributing to Climate Change SolutionsH. Kheshgi, ExxonMobil; F. Cappelen, Statoil; A. Lee, Chevron; S. Crookshank, API; A. Heilbrunn, CONCAWE; T. Mikus, Shell; W. Robson, Nexen; B. Senior, BP; and T. Stileman and L. Warren, IPIECAAbstract Concern about global climate change and the challenges and risks it poses will require sustained efforts to develop understanding and effective solutions while at the same time meeting the growing needs of society for energy. The development and utilization of technologies to capture and then store CO2 in underground formations offer significant potential for reducing CO2 emissions. This paper is based on the outcomes of an IPIECA workshop to advance understanding of the role of CO2 capture and geologic storage and strategies to improve its performance and prospects. It considers CO2 capture and geological storage as a potential option for reducing future emissions of Greenhouse Gases (GHGs) from the extraction of resources the production and use of fuels and the generation of electricity. In doing so it examines: roles CO2 capture and geologic storage may play over the next century extending from the current assessment of this technology family; risk management to ensure safe and secure geologic storage drawing from understanding and past experiences; public perception policy and regulatory frameworks that pose opportunities and barriers for CO2 capture and geologic storage and;initiatives and strategies to advance CO2 capture and geologic storage by reducing cost and risk and developing sound regulatory and policy frameworks to encourage development of options for deep reductions in CO2 emissions. Introduction Concern about global climate change and the challenges and risks it poses will require sustained efforts to develop understanding and effective solutions while at the same time meeting the growing needs of society for energy. Development and utilization of technologies to capture and then store carbon dioxide (CO2) in underground formations offer significant potential for reducing CO2 emissions. IPIECA convened an international workshop in October 2003 to advance understanding of the role of CO2 capture and geologic storage and strategies to improve its performance and prospects. The workshop brought together experts from academia business governments and intergovernmental and nongovernmental organizations to consider CO2 capture and geological storage as a potential option for reducing future emissions of greenhouse gases (GHGs) produced in the extraction of resources the production and use of fuels and the generation of electricity. Four sessions examined: the roles that CO2 capture and geologic storage may play over the next century; risk management to ensure safe and secure geologic storage drawing from understanding and past experiences; public perception policy and regulatory frameworks that present both opportunities for and barriers against CO2 capture and geologic storage; and initiatives and strategies to advance CO2 capture and geologic storage by reducing cost and risk and developing sound regulatory and policy frameworks to encourage development of options for deep reductions in CO2 emissions. This paper summarizes the IPIECA Climate Change Working Groups understanding of the presentations and discussions at the workshop. We are grateful to all participants for their efforts and contributions throughout the workshop which together with this publication is part of an ongoing effort by IPIECA to provide constructive input on key climate change issues.CHEVRONSPE116372CO2DisposalCase StudyGorgon Project: Subsurface Evaluation of Carbon Dioxide Dsposal under Barrow IslandMatthew Flett, SPE, Graeme Beacher, Jeroen Brantjes, SPE, Aaron Burt, Chris Dauth, SPE, Fiona Koelmeyer, SPE, Robert Lawrence, Seb Leigh, Jason McKenna, Chevron Australia Pty Ltd, Randal Gurton, William F. Robinson IV, SPE, Chevron Energy Technology Company and Terrell Tankersley, SPE, TengizChevroilAbstract The Gorgon Project is a major LNG development to be based in Northwest Australia. Gas will be produced from several offshore gas fields located in the Greater Gorgon Area with processing facilities to be located on Barrow Island. The reservoir fluids of several of the fields contain carbon dioxide (CO2) which will be extracted from the produced gases prior to liquefaction into LNG. The Gorgon Joint Venture participants have proposed to geologically dispose of the produced reservoir CO2 from the gas processed at the Barrow Island LNG plant. The CO2 injection project was extensively documented and subjected to public comment as part of the Gorgon Project Environmental Impact Assessment Process. Following this process the WA Environmental Protection Authority found that the environmental risks associated with the CO2 injection project were acceptable and recommended that CO2 injection must proceed as an integral component of the Gorgon Project. The target formation for geological disposal of this carbon dioxide is the Dupuy Formation a Jurassic saline reservoir deep beneath Barrow Island. The evaluation of the Dupuy Formation for the disposal of carbon dioxide was focused on characterising the reservoir and narrowing subsurface uncertainties not addressed by legacy oil exploration and development. Data acquisition was targeted to reduce major subsurface uncertainties including a seismic pilot to assess acquisition methods (including 4-D seismic) and an extensively evaluated appraisal well. Robust geological description hydrodynamic static and dynamic reservoir models have been used to gauge the impact of CO2 injection on development decisions. Key drivers for this development have been maximising per well injection of CO2 and ensuring containment of CO2 within the reservoir. Through effective subsurface and economic evaluation a phased and flexible development plan for CO2 disposal has been developed to meet these objectives. Introduction The Gorgon Joint Venture is an unincorporated joint venture of three major international oil companies; Chevron (Operator 50% interest) ExxonMobil (25%) and Royal Dutch Shell (25%). The Gorgon Project is a major capital LNG project that will produce gas from several offshore fields in the Greater Gorgon Area off the Northwestern coast of Australia. Figure 1 shows the development plan for the Gorgon Project. The Gorgon and Io/Jansz gas fields will be developed initially as a subsea development with a tie back to Barrow Island. On Barrow Island the raw gas will be received and undergo liquefaction into LNG for export. Production of gas is also being actively considered for supply into the West Australian domestic market. The Gorgon Project has needed to overcome several technical challenges during the concept selection phase of development: The project has one of the longest sub-sea tie-backs in the world (145kms) in water depths greater than 1km and challenging terrain with the pipeline crossing the continental shelf; Barrow Island is a remote location and a Class A Nature Reserve; The nearest major logistical staging point (Perth Australia) is over 1200km away from Barrow Island; Strict quarantine barriers to prevent environmental contamination; Finally the Gorgon gas field has a significant component of CO2 in the reservoir fluid composition with approximately 14% of Gorgon reservoir fluids being CO2.CHEVRONIPTC11391CO2StorageMechanistic Studies of CO2 SequestrationJ.M. Schembre-McCabe, SPE, and J. Kamath, SPE, Chevron Energy Technology Company, and R. Gurton, ChevronAustralasia SBUAbstract Geologic sequestration of carbon dioxide in aquifers or in hydrocarbon reservoirs offer a promising alternative to reduce the amount of CO2 released to the atmosphere. Most prior work has focused on CO2 containment. However target reservoirs can have low permeability and are often finite and the ability to properly model the injection stage is of significant economic concern. We conducted thorough mechanistic studies of the injection stage using a detailed compositional simulator. Issues that were probed included effects of mobile and immobile oil saturations damage due to geochemical reactions stimulation and presence of neighboring injectors. Total mobility plots signal effects of relative permeability curves on injectivity trends during the injection phase and help identify injectivity-damaging curves. Finally most studies on CO2 injection for disposal purposes assume that the reservoir has an infinite capacity for CO2 storage condition that is unlikely to be met by real-world projects. The low compressibility of water limits the amount of CO2 that can be stored in aquifers when no withdrawal of fluid is planned Finite storage size either due to finite reservoir size or presence of interfering injectors limits injectivity and it can have big impact on well counts needed project economics and total storage capacity. We also demonstrate that mechanisms present during injection stage in sequestration are very different from those in traditional Enhanced Oil Recovery operations due to its storage nature. Introduction The petroleum industry has been using carbon dioxide injection in enhanced oil recovery processes (EOR) since the 1970s. There has been recent interest in geologic sequestration of carbon dioxide in oil and gas reservoir to reduce the amount of CO2 released to the atmosphere. Geosequestration is the capture and long term storage such that anthropogenic CO2 is removed from the atmosphere for a significant perhaps geologic period of time. Because the objective of CO2 sequestration is to maximize the amount of CO2 injected and ensure that the CO2 remains safely confined the design of the CO2 injection changes from traditional CO2 injection design used for EOR processes. Thus variables that measure the success of these operations are different from those used in traditional gas injection. The two main value drivers of geosequestration projects are injectivity and containment. Over the last years studies have been mostly concerned with containment or secure trapping of CO2 which assess reliability of these projects. However well count development plan and operational limitations are important economic drivers. The focus of this paper is CO2 injectivity and the parameters that affect it. Injectivity I is defined as the ratio of a well volumetric flow rate q to a characteristic pressure drop or flow potential (p) I=q/p Eq. 1 Injectivity is a measure of the ability of placing a fluid into a geological formation and it affects directly well counting; therefore it is considered a key factor in any economic evaluation of a CO2 storage project. Because of the pressure term in the definition of injectivity (Eq. 1) injectivity is linked to the storage capacity of geological structure or reservoir. The pressure required to place CO2 into the formation gradually increases as the volume of CO2 builds up. As reservoir pressure increases the injectivity is diminished. Moreover maximum pressure applied during injection is limited by the maximum acceptable pressure increase without reactivating existing faults and/or creating new fissures. In the first part of the paper we use an infinite storage system to look at the effects of relative permeability presence of residual oil saturations (in order to simulate injection into a depleted oil reservoir) damage due to geochemical reactions and well stimulation. Most sequestration projects will have multiple injectors causing finite boundary effects and the second part investigates the impact of this on injectivity.CHEVRONSPE102968CO2Workshop 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. OnePetroCHEVRONSPE102968CO2Workshop PaperCapture/StorageCritical Issues in CO2 Capture and Storage: Findings of the SPE Advanced Technology Workshop (ATW) on Carbon SequestrationOnePetroCHEVRONSPE99548Corporate ProcessChevron's i-FieldCase StudyImplementing Chevron's i-field at the San Ardo, California, AssetJ. Ouimette, SPE, Chevron Energy Technology Co., and K. Oran, Chevron North America E&PAbstract This is a case study of an integrated digital oilfield project.The San Ardo California i-field Project is one of a number of current Chevron i-field implementation projects.It seeks to transform how the San Ardo steamflood is operated focusing on better decision making for the asset and streamlined work processes for heat wells and water management.The San Ardo i-field project is nearing the end of the planning and front-end engineering phases with project execution starting in 2006.The project team created preferred alternatives for transforming 21 work processes.Decision support software would be integrated with improved instrumentation workflow automation and data architecture to enable more reliable and efficient field operation and execution of reservoir management targets.The project is integrated in two ways.First integration occurs across the asset management value chain from reservoir through production optimization to day-to-day steamflood and facilities decisions and work processes.Secondly it is integrated across technology.For example reservoir surveillance signposts are created and used with computer models to move day-to-day decisions along correct trajectories for executing reservoir heating and production management.A common collaboration and visualization environment would be used for executing day-to-day field decisions.The knowledge provided in the paper would be helpful for assets where field operators are managing many wells with limited resources and attempting to improve their operability and efficiency. Introduction and description of San Ardo oil field The San Ardo field shown in Figure 1 is located in Monterey County California. The field includes the Aurignac and Lombardi unconsolidated heavy oil (12.5 gravity) sandstone reservoirs. The San Ardo Field was discovered in 1947 and to date Chevron has produced 257 MMBO of the field total 453 MMBO through primary cyclic steam and steamdrive operations. Chevron currently produces about 3 000 BOPD. Chevron plans to increase San Ardo production through a major capital project approved in 2005 which would add additional wells and associated infrastructure.The development plan consists of dewatering/depressurizing the reservoir while simultaneously expanding the number of steamflood patterns. A commercial reverse osmosis plant would be constructed to process produced water. The capital project would also be enhancing the data base infrastructure significantly.This creates a greenfield opportunity for i-field to take a fresh view when designing workflows.The i-field implementation is being phased in as the San Ardo major capital project begins its construction.CHEVRONSPE112260Corporate ProcessChevron's i-FieldNorth AmericaImplementation Results for Chevron's i-field in San Joaquin Valley, CaliforniaKenan Oran and James Brink, SPE, Chevron North America E&P Company, and James Ouimette, SPE, Chevron Energy Technology CompanyAbstract This paper summarizes results to date of implementing i-field projects in selected assets in Chevron's San Joaquin Valley Business Unit (SJVBU) in California. The i-field projects include collaborative environments to transform operational processes at a basin-wide or asset level remote collaboration and visualization has been implemented to help execute reservoir management and major capital project targets reliably and efficiently in the field. Successful asset prototypes are standardized and replicated across the business unit. The results to date demonstrate business value and take-up of the technology and processes by oilfield operations. Introduction The major producing assets of Chevrons SJVBU are shown in red in Figure 1. SJVBU production in 2007 averaged over 220 000 barrels per day from approximately 15 000 producing wells. Approximately 83% of the production was heavy 10% light and 7% gas. The heavy oil is generally recovered through thermal operations while the light oil is produced by waterflood. Unneland and Hauser (Reference 1) described the beginning of Chevrons digital oilfield program called i-field. Ouimette and Oran (Reference 2) summarized the use of decision support software integrated with improved instrumentation workflow automation and data architecture to enable more reliable and efficient field operation and execution of reservoir management targets at San Ardo within SJVBU. i-field has become critical to SJVBUs quest for operational transformation in pursuit of a vision to: Operate from a centralized asset decision environment where the application of smart oilfield technologies result in industry leading margin performance Integrate reservoir management with operations Automate routine decisions by artificial intelligence Create a highly virtual organization where innovation and collaboration efficiently move ideas to applied technologyCHEVRONSPE112267Corporate ProcessChevron's Knowledge ManagementSemantic Web Technologies for Smart Oil Field ApplicationsRamakrishna Soma, Amol Bakshi, and Viktor Prasanna, University of Southern California, and Will DaSie and Birlie Bourgeois, Chevron CorporationAbstract In model based oil field operations engineers rely on simulations (and hence simulation models) to make important operational decisions on a daily basis. Three problems that are commonly encountered in such operations are: on-demand access to information integrated view of information and knowledge management. The first two problems of on-demand access and information integration arise because a large number of and different kinds of simulation models each modeling a different facet of the oil-field are used. An engineer is generally an expert in one aspect of oil-field modeling and trained to use a few tools; therefore accessing information captured in models that do not lie in an engineers area of expertise is not easy. Moreover since these models are created by different processes and people the same information is represented differently across models. A unified view of the models and their simulations is desirable for decision making and thus the necessity for information integration. In the third problem- knowledge management problem we address the situation in which an engineer performs many analyses before making a decision. A systematic way to capture the rationale (knowledge) behind the various decisions is needed for audit tracking purposes as well as for future references. We examine the application of semantic web technologies to address these three problems present a prototype implementation which addresses them and provide an evaluation of the technology. 1. Introduction The work described in this paper is part of the Integrated Asset Management (IAM) project at the Chevron-funded Center for Interactive Smart Oilfield Technologies at the University of Southern California Los Angeles[17] . The current focus of the IAM project is on enabling model-driven reservoir management. As a motivating example consider a typical oil-field operation setting for a green field. Since little or no performance related data for the field exists the production engineer has to rely on simulations for making the initial set of asset development decisions. Different simulation models of the oil-field are created and used these include earth models reservoir simulation models network models integrated (coupled) simulation models etc.These simulation models are built and used at different times different locations and by different asset team members earth scientists reservoir engineers production engineers asset managers etc. A particular member of the team (say the reservoir engineer) is typically an expert in a particular modeling and simulation technology and intimately familiar with certain software toolkits in that domain. This also means that models workflows and results created by other software tools in other domains are not usable and accessible by that expert. As a result the insights and understanding of a team member in one role (say geologist) are not fully utilized by another role (say production engineer). Moreover these simulation models could be constantly modified as new data is continuously produced in the oil-field and interpreted by one or more members of the asset team. In this situation changes made to the model(s) by one team member should be immediately communicated to other team members who may be using that model as the basis of scenario planning and forecasting or who may need to modify their own models to match the updates. Three of the many problems that are observed in this setting are: Efficient access to information: No engineer has complete knowledge of all the data in the system and finding the relevant piece of information required to make a decision is a challenge. Unified view of the information: Every simulation model models one facet (reservoir network etc) of the oilfield in detail. However a unified view of the information related to the asset elements is generally not accessible from one place or application. Knowledge management: As the models are constantly being calibrated and decisions are taken the rationale (knowledge) behind the changes and decisions are generally lost. Such knowledge could be extremely useful for auditing the decisions made and also to train new engineers.CHEVRONSPE112259Corporate 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.CHEVRONSPE90213Corporate ProcessSPE's RTOReal Time OptimisationReal-Time Optimization: Classification and AssessmentS. Mochizuki, SPE, ExxonMobil; L.A. Saputelli, SPE, Halliburton; C.S. Kabir, SPE, Chevron Corp.; R. Cramer, SPE, Shell; M.J. Lochmann, SPE, Topsail Ventures; R.D. Reese, SPE, Case Services; L.K. Harms, SPE, ConocoPhillips; C.D. Sisk, SPE, BP; J.R. Hite, SPE, Business Fundamentals Group; and A. Escorcia, SPE, HalliburtonSummary The Real-Time Optimization (RTO) Technical Interest Group (TIG) has endeavored to clarify the value of real-time optimization projects. RTO projects involve three critical components: People Process and Technology. Understanding these components will help establish a framework for determining the value of RTO projects. In this paper the Technology component is closely examined and categorized. Levels within each Technology category are illustrated by use of spider diagrams which help decision makers understand the current status of operations and the future RTO status. The perception of uncertain value has been one of the critical issues in adopting RTO systems in our industry. Therefore case histories are reviewed to demonstrate the impact of RTO projects. To assist RTO project promotion further we list lessons learned suggest a justification process and present a simple example of an economic-evaluation process. Introduction Industry case histories demonstrate many types of benefits from RTO such as production-volume increase; better return on investment (ROI); higher decision quality; health safety and environment (HSE) improvements; and operational expenditures (OPEX) reduction. However they have lacked systematic project-evaluation processes for justification. Today promoting RTO is in essence a competition for capital within a company. The project teams that recognize this fact and then clearly outline the purpose benefits costs (direct or indirect) and strategic business alignment of their proposals will be in an advantageous position to secure funding. Because RTO is still an emerging discipline classifying projects of this nature is still dependent on an individuals point of view. This paper provides classification of RTO to help provide a common vocabulary to address a multitude of issues.CHEVRONSPE110236Corporate ProcessSPE's RTOReal Time OptimisationBarriors to Implementation of Real-Time Operations TechnologyJ. Roger Hite, SPE, Business Fundamentals Group; Charles Crawley, SPE, Chevron Energy Technology Company; David F. Deaton, SPE, Halliburton Digital Consulting; Kemal Farid, SPE, Merrick Systems; and Michael Sternevsky, SPE, MicrosoftAbstract The SPE Real Time Optimization Technical Interest Group conducted a survey of its members earlier this year to learn more about the barriers to implementation of this technology. Understanding the barriers better will allow us to focus on the more important issues. The survey was in two parts. The first asked about the overall process of getting from data to decisions and action. The second focused on the usage of technical and business tools. This paper summarizes the results of the survey. We found that each step in the process has considerable major and minor barriers to overcome. The most difficult steps were in the areas of business analysis recommendations / decisions and taking action. These are areas where management can have the greatest impact through improved work processes governance and procedures. The results also show there is considerable need for improved commercial technical and business analysis tools Introduction The digital oilfield is the subject of a great deal of interest and emphasis these days. It has enormous potential but seems to be slow in developing. This paper was conceived by the SPE Real Time Optimization Technical Interest Group (RTO TIG). (See http://www.merricksys.com/rto/) This is the fourth in a series of SPE papers sponsored by the RTO TIG1 2 3. In conducting this survey we were interested in learning more about the barriers to implementation of real time optimization technology especially the barriers associated with getting from data to decisions and action. With the help of SPE International a survey of TIG membership was conducted early this year to gain insight into these barriers. Understanding them better will allow us to focus on the more important issues. A related analysis was published earlier by Liddell Deaton and Mijares4. A summary of the results of this survey are contained in this paper. The Survey The survey was sent via e-mail to members of the RTO Technical Interest Group. The survey questionnaire was in two parts. 1. The first asked about the overall process of effective implementation. Effective utilization of RTO involves a process of gathering and analyzing data making recommendations and decisions and taking action (Figure 1). Perhaps the process was working smoothly everywhere although we expected there are some snags somewhere. The survey recipients were asked to provide their perspective on where along the process the current difficulties lay. In other words where is the wasted effort and lost time? 2. The second part focused on the usage of technical and business analysis tools where we suspected major barriers were limiting adoption. We were particularly interested in the application of analysis tools for technical and business applications. This questionnaire was focused primarily on wells and subsurface application tools. Respondents Over 200 people responded. About half worked for producing companies while the other half worked for providers - a fourth worked for service companies and a fourth were vendors consultants and academics. About two-thirds worked onshore and one-third offshore. While similar there were some differences between responses from the producers and the providers. In this paper we have highlighted results from the producers but noted responses from providers as well.CHEVRONSPE97228EOR/IORBy-passed OilRecovery MechanismsMitigating Oil Bypassed in Fractured Cores During CO2 Flooding Using WAG and Polymer Gel InjectionsD. Chakravarthy and V. Muralidaharan, Oxy U.S.A.; E. Putra, Kinder Morgan CO2 Co. L.P.; D.T. Hidayati, Chevron; and D.S. Schechter, Texas A&M U.Abstract Fractured reservoirs have always been considered as poor candidates for enhanced oil recovery. The fractures provide a pathway for injected fluids to channel through directly from injection to production wells. The interaction between these fractures and the reservoir rock matrix often determines the degree of bypassing during injection of CO2. The use of CO2 as a displacing agent through these reservoirs aggravates the problems of low sweep efficiency due to its high mobility. The microscopic displacement efficiency of CO2 is very high but the overall displacement efficiency is often hindered by its high mobility that is largely the results of viscosity and density contrasts between the CO2 phase and the reservoir oil and brine phases. In this study we performed CO2 injection experiments with different injection rates and utilized X-ray CT to determine the saturation distribution along the core and measure oil bypassed during CO2 process in fractured cores. We improved the CO2 sweep efficiency by controlling the CO2 mobility in the fracture. Water viscosified with a polymer was injected directly into the fracture to divert CO2 flow into the matrix and delay breakthrough. Although the breakthrough time reduced considerably water leak off into the matrix was very high. To counter this problem a cross-linked gel was used in the fracture for conformance control. The gel was found to overcome leak off problems and effectively divert CO2 flow into the matrix. This experimental results increase the understanding of fluid flow and conformance control methods in fractured reservoirs. Introduction CO2 injection has been widely used for recovering oil from reservoirs due to its easy solubility in crude oil and its ability to swell the net volume of oil and thereby reduce oil viscosity by a vaporizing-gas-drive mechanism (Martin and Taber 1992). The quantity of hydrocarbons that can be recovered from a reservoir is influenced by several characteristics of the reservoir including reservoir rock properties reservoir pressure and temperature physical and compositional properties of the fluid and structural relief to name a few. However the predominant factor in deciding the success of a CO2 flood is the reservoir heterogeneity. Highly heterogeneous reservoirs with variable lateral and vertical permeability characteristics can cause potential problems during CO2 injection. The injection gas tends to finger ahead into areas with high mobility ratios. This results in the gas forming preferential paths and bypassing large volumes of oil. Uleberg and Hoier (2002) suggest that the injection gas tends to flow in the highly permeable fractures instead of the normally expected displacement path. These fractures are often responsible for early and excessive breakthrough of CO2 thus greatly affecting the economics of the project. In the recent years there has been an increasing interest in the WAG process both miscible and immiscible. The continuous CO2 injection process is an important process to identify displacement mechanisms but is not likely to be economic in practice unless significant recycling of gas is employed. Inherent in all gas injection processes is the lack of mobility and gravity control (areal and vertical sweep) necessary to sweep significant portions of the reservoir. Therefore the replacement of high cost CO2 by a cheaper chase fluid such as water for horizontal displacements appears economically attractive. The WAG process involves alternate injections of small pore volumes (5% or less) of CO2 and water until the desired volume of CO2 has been injected. Since the microscopic displacement oil by gas normally is better than by water the WAG injection combines the improved displacement efficiency of gas flooding with an improved macroscopic sweep by the injection of water. This has resulted in an improved recovery (compared to pure water injection) for most field cases.CHEVRONSPE100089EOR/IORChemical FloodingSurfactantIdentification and Evaluation of High-Performance EOR SurfactantsDavid B. Levitt, SPE, Adam C. Jackson , SPE, Christopher Heinson, SPE, and Larry N. Britton, The University of Texas at Austin; Taimur Malik, and Varadarajan Dwarakanath, SPE, Intera; and Gary A. Pope, SPE, The University of Texas at AustinSummary We report results for a number of promising enhanced-oil-recovery (EOR) surfactants based upon a fast low-cost laboratory screening process that is highly effective in selecting the best surfactants to use with different crude oils. Initial selection of surfactants is based upon desirable surfactant structure. Phase-behavior screening helps to quickly identify favorable surfactant formulations. Salinity scans are conducted to observe equilibration times microemulsion viscosity oil and water-solubilization ratios and interfacial tension (IFT). Cosurfactants and cosolvents are included to minimize gels liquid crystals and macroemulsions and to promote rapid equilibration to low-viscosity microemulsions. Branched alcohol propoxy sulfates (APS) internal olefin sulfonates and branched alpha olefin sulfonates (AOS) have been identified as good EOR surfactants using this screening process. These surfactants are available at a low cost and are compatible with both polymers and alkali such as sodium carbonate and thus are good candidates for both surfactant-polymer and alkali-surfactant-polymer EOR processes. One of the best formulations was tested in both sandstone and dolomite cores and found to give excellent oil recovery and low surfactant retention with a west Texas (WT) crude oil. Introduction Recent advances including the development of new synthetic surfactants and increased understanding of the structure/performance relationship of surfactants have made it possible to rapidly identify promising high-performance surfactants for EOR. This process involves laboratory screening using knowledge of the molecular structure and cost of the surfactants as well as pertinent reservoir-specific information (i.e. temperature salinity and crude-oil properties). This paper describes a process for identifying and evaluating potential EOR surfactants. The surfactant selection process starts with the screening of surfactants by phase-behavior experiments and progresses to corefloods with formulations that may incorporate cosurfactants cosolvents alkali polymers and electrolytes. We illustrate the application of this approach to the selection of a surfactant formulation for use in both a sandstone outcrop and a WT dolomite reservoir but focus mostly on the dolomite application because very few studies have been reported for carbonate (Adams and Schievelbein 1987) or dolomite reservoirs. These laboratory data were used in a parallel simulation study of the same reservoir and are described by Anderson et al. (1976) in a companion paper.CHEVRONSPE113965EOR/IORChemical FloodingSurfactant selectionUsing Co-Solvents to Provide Gradients and Improve Oil Recovery During Chemical Flooding in a Light Oil ReservoirV. Dwarakanath, SPE, T. Chaturvedi, SPE, A.C. Jackson, SPE, Chevron; T. Malik, SPE, A. Siregar, SPE, and P. Zhao, SPE, ChevronAbstract The effect of co-solvent on phase behavior was evaluated and an optimal surfactant/co-solvent formulation was selected based upon a combination of simulations and laboratory experiments. The co-solvent altered phase behavior thereby necessitating a different approach for inducing effective salinity gradients. We present an approach where the hydrophilic nature of the co-solvent is used to maintain effective salinity gradients to optimize surfactant behavior but more importantly mitigate viscous microemulsions and reduce surfactant retention. By using a combination of laboratory experiments and simulations to match co-solvent behavior in UTCHEM Using an understanding into co-solvent partitioning was developed such that the optimal conditions of ultra-low interfacial tensions are maintained for a longer duration during chemical flooding. We demonstrated that by adding the appropriate co-solvent and the correct amount of electrolyte in the chase solutions we could maintain Winsor type III conditions for extended durations even with a small surfactant slug. The optimal co-solvent/electrolyte gradient recovered more than 90% of the residual oil in laboratory corefloods. The result illustrate the importance of characterizing the effect of co-solvent on surfactant phase behavior and the need for numerical modeling to optimize chemical flood design when co-solvent is used. Introduction The success of surfactant flooding rests on the ability of surfactant-oil mixtures to rapidly coalesce to form fluid and stable microemulsions with ultra-low tensions. Recent developments in the area of surfactant synthesis and screening have allowed the selection of high performance surfactant formulations for enhanced oil recovery.1 2These high-performance surfactant formulations require co-solvents to (a) improve phase behavior; (b) reduce microemulsion viscosity; and (c) ensure surfactant-polymer compatibility.1 2 Such surfactant/co-solvent formulations show high oil recovery and low surfactant retention in corefloods. Numerical simulations are an important component to scale-up chemical flooding from lab to field-scale. Numerical simulations require matches of surfactant phase behavior and corefloods to obtain parameters for field-scale simulation. In typical simulation studies the effect of co-solvent is usually neglected3 4 5 and gross surfactant parameters are often used to capture chemical phase behavior. While this approach may be appropriate for formulations that use no co-solvent a design that includes the effect of co-solvent on surfactant phase behavior is preferred for accurate field-scale predictions. Co-solvents used for oil recovery are amphiphiles6 7 and have the ability to partition into aqueous oleic and microemulsion phases. The ability to partition between the three phases allows co-solvents to significantly alter phase behavior. When a hydrophilic co-solvent is mixed with an anionic surfactant an increase in optimal salinity is observed. Conversely a lipophilic co-solvent will induce a reduction in optimal salinity. From these observations Hedges8 used co-solvent scans to identify the appropriate co-solvent for a fixed optimal salinity. While co-solvents have been used widely in surfactant trials their effect on phase behavior is often neglected due to the complexity of experimental measurements and incorporation into numerical simulation. An adverse consequence of ignoring co-solvent behavior could be chromatographic separation from the surfactant due to preferential partitioning. Such separation would induce changes in overall surfactant/co-solvent compositions along a dilution path and undesirable phase behavior.CHEVRONSPE99656EOR/IORHeterogeneityChemical TreatmentTransport of a pH-Sensitive Polymer in Porous Media for Novel Mobility-Control ApplicationsS.K. Choi, SPE, U. of Texas at Austin; Y.M. Ermel, SPE, Chevron Corp.; and S.L. Bryant, SPE, C. Huh, SPE, andM.M. Sharma, SPE, U. of Texas at AustinAbstract Injection of a pH-sensitive polymer into a heterogeneous reservoir as a novel deep-penetrating mobility control method has been proposed earlier (Al-Anazi and Sharma 2002b).A polyelectrolyte that forms molecular-network microgels in solution is injected into high-permeability zones under acidic conditions.Upon contact with reservoir rock the injected fluid experiences an increase in pH due to geochemical reactions between the injected fluid and carbonate and other mineral components in the rock.The pH increase swells the polymer which drastically increases the apparent viscosity of the polymer solution significantly lowering the mobility of water in the high-permeability zone.For the controlled application of this novel process the mechanisms for each of its three sub-processes need to be understood: (1) dependence of polymer viscosity on ionic (pH) conditions in the reservoir; (2) geochemical characterization of pH change in the rock; and (3) polymer microgel transport in porous media. Viscosity characterization has been reported earlier (Huh et al. 2005). The geochemical characterization and the microgel transport are reported in this paper. For geochemical characterization brine at pH=2 was injected into a Berea sandstone core.The pH and cation concentrations in the effluent were matched employing our geochemical simulator KGEOFLOW.An approximate representation of sandstone with three mineral components adequately matched the pH change during the acid-injection coreflood. For a preliminary characterization of soft microgel transport a pure-silica sandpack at a constant pH was employed to remove any geochemical effects (i.e. no microgel swelling).From the pressure gradient data available from internal pressure taps the permeability reduction due to polymer retention was obtained as a function of polymer structure (represented approximately by rheological parameters) and polymer concentration and with addition of surfactant.The retention can be explained by adsorption on the silica surfaces with a small contribution from straining by size exclusion. Introduction Poor sweep efficiency due to reservoir heterogeneity is a significant concern for the production of oil and gas from a vast majority of reservoirs. Improving reservoir sweep is therefore of paramount importance for successful reservoir management.To control premature production of water or gas or in general to improve reservoir sweep efficiency polymer gel has been extensively employed as a conformance control agent.The most common gel placement method is the injection of polymer and crosslinking agent into the thief zone and allowing them react to form gel in-situ.Because it is difficult to control the transport and reaction of the chemicals in a heterogeneous reservoir the success of the field applications of in-situ gellation has been mixed (Seright and Liang 1994).Surface-prepared microgels do not have the above reaction control problem but are difficult to place deep in the reservoir because they cause very large pressure drops near the injection well and also tend to show mechanical trapping and filtration.In earlier years therefore much of the surface-prepared gel applications have been near wellbore treatments for vertical conformance control.CHEVRONSPE112375EOR/IORModelling - Near Wellbore EffectsGravity SegregationWell Stimulation and Gravity Segregation in Gas Improved Oil RecoveryM. Jamshidnezhad, Delft University of Technology; C. Chen, Chevron Energy Technology Company; and P.Kool and W.R. Rossen, Delft University of TechnologyAbstract Models for gravity segregation in gas improved oil recovery (IOR) indicate that the distance injected gas and water travel together before complete segregation scales with the injection rate Q. Therefore in cases where injection pressure is limiting reducing skin resulting from damage at the wellbore face directly increases volumetric sweep of gas in IOR. Even in the absence of damage at the wellbore face most of the injection pressure is dissipated near the well but most of the segregation occurs much further from the well. Therefore if injection pressure is limited increasing mobility near the injection well has a large impact on Q with a direct benefit in delaying gravity segregation. There is also a relatively small increase in gravity segregation in the near-well region. An analytical model for gravity segregation in homogeneous reservoirs can be extended to a case where permeability is stimulated within a cylindrical region inside a larger cylindrical reservoir. The effect of this stimulation in increasing Q at fixed injection pressure can be estimated as well. One can increase the volume swept by gas before segregation by as much as 170% though a large volume must be stimulated to reach this optimum. The model represents schematically a number of ways proposed in gas IOR for delaying segregation beyond the possibilities with uniform steady co-injection of Newtonian fluids: alternate injection of gas and liquid (WAG or SAG with foam); injection of gas above water; and injection of shear-thinning foam. In all these cases the process gives higher mobility near the well allowing an increase in injection rate and thereby increases the distance to the point of segregation. The model can be extended directly to the case of shear-thinning (power-law) foam. One obtains a differential equation for the segregation process in place of the algebraic equation that results for Newtonian fluids. In the limit of extremely shear-thinning behavior it is possible to double the distance to the point of segregation with no increase in injection pressure. Simulations fit the theoretical prediction well. Introduction Injection of gases (steam CO2 or hydrocarbon gas) is an important method for increasing recovery in declining oil fields. Gas improved oil recovery (IOR) can in principle recover nearly all the oil in place but sweep efficiency of injected gas is poor (Lake 1989). Reasons for poor sweep efficiency include reservoir heterogeneity low density of gas and low viscosity of the gas. In relatively homogeneous reservoirs low gas density leading to gravity override can severely limit gas sweep and oil recovery. In most cases gas is injected together with or alternating with water to reduce gas mobility.CHEVRONSPE120205EOR/IORSteamfloodingWafra FieldSteamflood Piloting the Wafra Field Eocene Reservoir in the Partitioned Neutral Zone, Between Saudi Arabia and KuwaitDavid Barge, Falah Al-Yami, Don Uphold, Alireza Zahedi, and Art Deemer, Saudi Arabian Chevron, Patricia E. Carreras, Chevron Energy Technology CompanyAbstract The concept of steamflooding the Wafra Eocene dolomite reservoir originated in various studies conducted in the 1980s. In 1999 a comprehensive EOR study and Eocene huff-n-puff pilot suggested that steamflooding could be a viable recovery process for the reservoir. As a result of these studies a staged development approach was incorporated to test the viability of pattern steamflooding the Eocene reservoir. The objective was to assess key technical challenges associated with steamflooding an anhydrite and gypsum rich carbonate reservoir. Additional challenges were the lack of fresh water available for steam generation high concentrations of hydrogen sulfide gas and higher reservoir pressures compared to most active steamfloods. The staged approach called for a single pattern steamflood test followed by a larger multi-pattern pilot. As a result of this strategy a single pattern steamflood test was implemented in 2006. The design and initial performance of the small scale test (SST) single pattern steamflood pilot in the Wafra 1st Eocene reservoir are described in this paper. The pilot is comprised of one 1.25 acre inverted five-spot pattern consisting of four producing wells a single injector and a single observation well. Continuous steam injection began in February 2006 at a rate of approximately 500 barrels per day cold water equivalent 600 psig and a temperature of 489 F. The primary goals of the single pattern test were to test application of a mechanical seeded slurry evaporator to process produced water for steam generation and to assess steam injectivity into dolomite reservoirs containing gypsum and/or anhydrite. Injectivity assessment included evaluating reservoir response to steamflooding and investigating the variation over time due to rock/fluid interactions. Secondary objectives included analyzing well productivity and evaluating well testing equipment facilities and well construction. The SST has a comprehensive data collection and surveillance plan to support evaluation of these goals and objectives. The surveillance plan includes the collection of pre-flood and post-flood core data frequent well testing for rates and fluid compositions daily temperature recordings and periodic logging. After two years of operation primary goals have been tested and exceeded expectations.A continuous thermal zone was developed in the 1st Eocene reservoir and steam breakthrough occurred at several of the producers. Generator feed quality water was produced at maximum throughput rate of 1 200 bwpd via mechanical seeded slurry evaporator equipment. Secondary objectives are currently being assessed with focus on current challenges ofcorrosion and scaling of producing wells.CHEVRONSPE102219EOR/IORWell InterventionWater Shut-offWater Shutoff Treatments Using an Internally Catalyzed System in Boscan Field: Case HistoriesF. Mata, SPE, BJ Services de Venezuela CCPA, and S. Ali, SPE, and Ernesto Cordova, Chevron Global Technology Services Co.Abstract This paper describes the results obtained using an Internally-Catalyzed System1 (ICS) to reduce water production in the Boscan oil field near Maracaibo West Venezuela. This field is divided in two blocks: north and south. In the south block wells can eventually produce oil with 90% water cut due to the influence of an aquifer. The accumulated production per well can be as high as 6 (six) million barrels and typical rates range from 600 to 2 400 BFPD (barrels of fluid per day). In order to mitigate the high water cut and water production the operator implemented in 1998 a water shut-off (WSO) program. In 2003 the ICS was introduced as part of this program. The ICS is solids-free and internally activated. It is used for permanent zone plugging and lost circulation control delivered into the matrix of the targeted zone. Laboratory evaluations were conducted to determine effects on the hard setting of ICS resulting from the contact between ICS and other fluids deployed on well construction and well production enhancement as well as reservoir fluids acids cement filtrate brines formation water and crude oil. This paper summarizes the results of 19 WSO jobs performed.. In some specific wells water cut decreased by 20%; on others by 70% with consequent oil production increase in some cases of more than 400 BOPD per well. The WSO treatments have been designed for deeper formation penetration and long-lasting water blockage. Applied WSO treatments with ICS have been found to effectively block water production over a long period. Cost of treatments has been paid out within approximately 45 days. This paper includes laboratory tests operational procedures and results for each treatment done with ICS technology demonstrating to be an excellent option to enhance oil recovery on mature fields with water high water production. Introduction Boscn field is located near to Maracaibo Zulia State at west of Maracaibo Lake with a total area of 627 Km2 (Figure 1). This field have being producing since 1940 actually is operated by the Joint Venture Petroboscan (PDVSA and Chevron). More than 1.2 billion barrrels of 10.5 API oil have been produced through artificial lift. The estimated original oil in place (OOIP) is 36.84 billion barrelsl and recoverable reserves of 2.47 billion Barrels. Primary production began in 1947 with an initial reservoir pressure of 3 450 psi and it has declined to a current average reservoir pressure of 1 500 psi. The production goal in this field is 115 000 BOPD. This can be reached by the data gathering and implementations of processes to optimize and mantain the levels of production over the life of the field. Boscn is characterized by low pore pressure reservoirs high pressure and large underlaying active aquifer in the south block (Figure 2) high accumulated production and high production rates. Due to a rising Water Oil Contact (WOC) high water cut levels have been observed on deeper production zones. Wells located in the south block of the field have most of the water production this zone has been producing for more than 50 years is partially depleted and wet sands are part of the production intervals (Upper Boscn) with water cut ranging from 60 to 90% in this area.CHEVRONSPE111512EOR/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 cleanup of the isolated producing layers. The results of ten water control treatments are presented here. The average water cut was reduced to 30% from 88% and oil production was increased by an average of 300 BOPD per well through the application of this water shut-off solution. In one particular well two previous water control treatments using a conventional water shutoff technique including a relative permeability modifier (RPM) had left the well producing 100% water. The new solution reduced the water cut to 25% resulting in a gain in oil production of 300 BOPD. This innovative solution was established as a standard practice for water shutoff in the Boscan field. Introduction The Boscan field lies 40-km southwest of Maracaibo Venezuela and covers an area of approximately 660 km2 produces a 10.5API gravity asphaltic oil from the upper Eocene Boscan (Misoa) Formation with a live oil viscosity ranging from 200-400 cp at reservoir conditions. The reservoir dips to the southwest and ranges from 5000 to 9000 ft in depth. Boscan Field is a combination structural/stratigraphic trap. The reservoir sands were deposited in a tidal-dominated depositional setting. Boscan Field has a complex stratigraphic framework the interpretation of which is made particularly difficult by the 1 to 0.6 kilometer well spacing. The field currently produces ~ 115 000 BOPD. Figure 1 shows the geographic location of the Boscan field. Since its discovery by the Richmond Exploration Company in 1947 the Boscan field has had over 800 wells drilled with 525 of them currently active. Most of the shut-in wells in the field are located in the south end of the field that in recent years has experienced a surge in water production. Most of the wells in this particular area are experiencing water cut of 90% or higher. Problem Scope The main production challenges in south Boscan wells are; 1) Surface facility limitations in handling produced water; therefore the volume of fluid produced is limited. In addition production enhancement is restricted.CHEVRONSPE121761EOR/IORWell InterventionWater Shut-offIncremental Oil Success From Waterflood Sweep Improvement in AlaskaDanielle Ohms, SPE, Jennifer McLeod, SPE, and Craig J. Graff, SPE, BP Alaska; Harry Frampton, SPE, BP EPT; Jim C. Morgan, SPE, Jimtech; Stephen Cheung, SPE, Chevron; and Katrina Yancey, SPE, and K.T. Chang, SPE, NalcoAbstract Waterflood thief zones in communication with the rest of the reservoir are a severe and previously challenging problem. This paper gives an introduction to the nature of a novel heat-activated polymer particulate. Details of a trial of this indepth diversion system resulting in commercially significant incremental oil from a BP Alaskan field are presented. The system of one injector and two producers was selected because of a high water oil ratio and low recovery factor which was recognized as an indicator of the presence of an injection water thief zone and confirmed by study of a previous injection survey. The area around the wells is bounded by faults so the system can be considered to be isolated from surrounding wells and operations. The position of the thermal front in the reservoir tracer transit times injection rates and inter-well separations indicated that the slowest reacting of the three commercial grades available was most appropriate for the trial. The treatment was designed using laboratory tests and numerical simulation informed by pressure and chemical tracer tests. Long sandpack tests indicated permeability reduction factors of 11 to 350 for concentrations of 1500 to 3500 ppm active particles in sand of 560 to 670 mD permeability at149F. 15 587 gallons of particulate product was dispersed using 8 060 gallons of dispersing surfactant into 38 000 barrels of injected water and pumped over 3 weeks at a concentration of 3300 ppm active particles. Placement deep in the reservoir between injector and producer was confirmed by pressure fall off analysis and injectivity tests. The incremental oil predicted from the simulation was 50 000 to 250 000 bbl over 10 years. In fact over 60 000 barrels of oil was recovered in the first 4 years at a cost comparable with traditional well work and less than sidetracking. Introduction In a 2004 SPE Distinguished Lecture it was stated that the world wide recovery factor for oil will be less than 33 percent1. Even achieving 40 percent would abandon significant residual oil unless innovative steps are taken to recover it. Recovery factor can be increased by improved access displacement or sweep. Access is typically the domain of sidetrack and infill drilling. Improved displacement is addressed by Enhanced Oil Recovery methods. There has been a shortage of tools for improving sweep particularly when thief zones or channels are in contact with lower permeability less efficiently swept zones and an in depth block is needed to achieve commercial oil recovery2. A range of thermally sensitive particulate products have been developed for in-depth waterflood sweep control. They are sub-micron sized particulate systems supplied as 30 percent active emulsions in light mineral oil. The technology recently proved successful in a technical field trial3 4. Evidence of the commerciality of the technology was required. The purpose of the trial discussed here was to measure the commercial effect on a small number of isolated wells. The BP Milne Point field is on the North Slope of Alaska. The reservoir shows structural compartmentalisation into separate fault blocks called Hydraulic Units or HUs. The fault density is moderate with two dominant orientations few open fractures and a poorly connected fracture system. The reservoir quality is relatively uniform though a thief zone is present in the B7 upper sand. Vertical flow barriers are few and/or discontinuous. The commercial trial treatment of Milne Point B-12i injector had the objective of increasing the oil rate at the associated producers B-03 and B-04A. This would lead to higher ultimate oil recovery from HU152.CHEVRONSPE102352Flow AssuranceModelling - Slug TrackingCase StudyPipelines Slugging and Mitigation: Case Study for Stability and Production OptimizationY. Tang, SPE, Chevron Energy Technology Co., and T. Danielson, SPE, ConocoPhillips Upstream Technology Co.Abstract The ConocoPhillips Alpine facility on the Alaskan North Slope has experienced slugging problems severe enough to trip the high-high inlet separator level causing frequent plant shutdowns and loss of production of 110 kbbl/d. A slugging study was commissioned to investigate the cause of the existing CD-2 pipeline slugging and possible mitigation procedures which could alleviate and/or eliminate slugging. Further the Alpine expansion called for an additional two pipelines (CD-3 and CD-4) to be brought into Alpine inlet separator. Slugging mechanism and instability analysis were performed. The instability is due to combination of its low flow rate overly-sized pipeline ID and unfavorable pipeline profile. Flow pattern transition exists at the low spots and liquid accumulates and blocks the flow. In the low pressure system once gas blows out and system pressure drops the pipeline inlet gas increases velocity and picks up a new hydrodynamic slug. This slug moves through the road crossing and the pipe rack riser becoming a long slug which arrives at the separator. In this study a slug-tracking model with separator gas/liquid PID controllers was built to reproduce the field SCADA data. A remarkably good match of pressure variations slugging frequency and liquid level was achieved. A sensitivity study was performed to investigate the effective and practical ways to suppress slugging in the existing CD-1 and CD-2 pipeline. Finally a combined control was recommended by installing a by-pass control valve at the butterfly valve location. The by-pass inlet control valve before the separator acquires separator liquid level signal and actuates when the separator liquid level exceeds the set value. This significantly reduces slugging effect on separator performance. The slugging model and results based on the existing CD-2 pipeline were applied to the future expanded CD-3 and CD-4 pipeline study. Some conclusions were drawn from the slugging behavior. Introduction In many oil and gas developments with multiphase flowlines production instability due to slugging is a major flow assurance concern. Slugging initiates oscillations puts excessive demands upon the separation and operation and increases the wear and tear of equipment. Large liquid surges can cause poor performance separator shut down high pressure trips or flaring. Slugging can be characterized by periodical change of pressure and gas/liquid flow. The slugging severity depends on slugging types. There are three types of slugging: Hydrodynamic slugs: a feature of the slug flow regime where slugs are continuously formed due to instability of waves at certain gas-liquid flow rates. Generally hydrodynamic slugs do not exceed 20 times of pipe diameters if there is no obvious inclination change. Operationally induced surges: generated by changing the flow conditions from one steady state to another such as restart flow rate ramp-up or pigging operations. The generated liquid surge can upset the system. Terrain induced slugs: also called severe slugs caused by accumulation and periodic purging of liquid in flowline dips at low flow rates;CHEVRONSPE103137Fluid descriptionAsphaltenesScreeningScreening for Potential Asphaltene ProblemsJ.X. Wang, SPE, New Mexico Tech.; J.L. Creek, SPE, Chevron; and J.S. Buckley, SPE, New Mexico Tech.Abstract We present a rapid screening technique that uses a minimal amount of measured data. Only in cases where asphaltene precipitation is predicted by the screening test would further experimental evidence such as the measurement of onset pressure be required. Currently the criteria introduced by de Boer et al.1 are widely used for screening purposes. In general these criteria yield predictions that are somewhat pessimistic in part because they fail to account for differences in stability between specific oils and their asphaltenes. In this paper we propose a practical screening method that is easily applied yet can dramatically improve the accuracy of stability predictions. The method is a modification of the ASphaltene InStability Trend (ASIST) technique2 for predicting the onset pressure during depressurization. The information required in the simplified screening method includes routine PVT data compositional analyses and a single onset titration using stock-tank oil and a light n-alkane precipitant such as n-heptane. The predicted onset solubility parameter at the bubble point is compared with the calculated solubility parameter of crude oil at that pressure to determine whether asphaltene would become unstable and precipitate. Twenty-seven crude oil samples from many different locations have been used to develop and test this method. Results are in agreement with the more detailed ASIST predictions and clearly identify specific cases where de Boer predictions are overly pessimistic. Introduction The best known most widely used screening method for evaluating the risk of asphaltene precipitation during depressurization is that proposed by de Boer et al.1 In fact de Boer and his coauthors suggested a range of tests of varying complexity but it is the simplest evaluation based on (1) the difference between reservoir and bubble-point pressures (2) density of the reservoir fluid and (3) asphaltene saturation at reservoir conditions as summarized in what is often referred to as a de Boer plot (Fig. 1) that is widely used. The unstable (severe problems) and stable (no problems) regions are delineated based on calculations of asphaltene supersaturation using the Hirschberg model.3 An intermediate area labeled slight problems lies between the extremes and is bounded by calculated supersaturation values of 1 and 2 (assuming the solubility parameter of asphaltene da is 20 MPa1/2). Although the de Boer plot clearly distinguishes very stable oils (e.g. Boscan) from very unstable ones (e.g. Hassi Massoud) experience over the past decade has shown that predictions tend to be somewhat conservative indicating asphaltene precipitation in cases where no problems develop in the field. Such false positive predictions can occur (1) in cases where precipitation occurs without causing any field problems and (2) because of certain inaccuracies and oversimplications that are built into the de Boer plot itself. Type 1 situations may exist in fields where flocculated asphaltenes are observed in separators but not in production lines. Discrepencies of the second type can be averted using the improved screening method described in this paper.OnePetroCHEVRONSPE121414Fluid DescriptionCore TestingAsphaltene DepositionCore Flood Investigation Into Asphaltene Deposition Tendencies in the Marrat Reservoir, South East KuwaitN.H.G. Rahmani, SPE, J. Gao, SPE, and M.N. Ibrahim, SPE, Schlumberger; S. Bou-Mikael, SPE, Chevron Corp.; and B.S. Al-Matar, SPE, and F. Ruhaimani, SPE, Kuwait Oil CompanyAbstract Asphaltene precipitation can have profound effects on oil production during miscible flooding heavy oil recovery or even primary depletion. Even though asphaltene precipitation and eventual deposition have been known to have strong effects on permeability reduction (Turta et al. 1997; Minssieux et al. 1998) quantitative analysis of the process has not been studied extensively. This paper describes experimental work conducted to study the precipitation and deposition tendencies of asphaltenes within the rock material in the Marrat reservoir South East Kuwait. Live asphaltenic reservoir fluids and carbonate cores of the Marrat reservoir were recovered and used at reservoir pressure and temperature conditions during core flood experiments. The live Marrat reservoir fluid was fully characterized and subjected to pressure depletion tests to determine the asphaltene onset point at various temperatures. The results reveal preferential deposition of the precipitated asphaltenes with respect to the rock material. The characterization of the rock materials by CT-Scans had indicated the presence of local occluded porosities. These occluded sites were found to be the main influence on the pattern of deposition seen in the core samples. The study shows clearly that although asphaltenes may precipitate and deposit from the Marrat reservoir fluid the propensity for permeability damage is in fact determined by the nature of the rock material. In addition the tendency of the precipitated asphaltenes to aggregate into larger flocs that are generally friable influences the rock damage potential. Handling and treatment of asphaltenic fluids will continue to impact on reservoir operations project costs and recovery efficiencies. Understanding the nature of asphaltenes and how they impact on the sub-surface behaviour of reservoir fluids will become more pertinent as global oil demand forces a move towards heavy oils and / or highly asphlatenic fluids. Introduction Asphaltene precipitation and eventual deposition is recognised as one of the major operational problems confronting oil and gas asset operators worldwide. The problem can manifest at any point within the oil production and delivery chain depending on the local pressure temperature or composition of the fluid (Leontaritis 1989). The overall resultant effect is a choke-back and/or interruption to production (at surface) while in the sub-surface the effect could be very severe resulting in rock damage and possible loss of producible reserves. Asphaltene precipitation and deposition within the production system comprising the wells flow lines and surface facilities is far less problematic compared to its precipitation and deposition in the pores of reservoir rocks simply due to ease of access and the possibility of designing and deploying remedial treatments. Deposition in the production system can usually be treated relatively easily by chemical or mechanical means (Moricca and Trabucchi 1996). Chemical treatment may involve the flushing of the system with a solvent such as Xylene. Mechanical treatment usually involves the deployment of a scraper or some other device to remove the deposited sludge. Deposition in the sub-surface rock pore system is very difficult to deal with. Not only is the deposition itself a hindrance to the flow including possible plugging of the delivery paths of the reservoir fluids to the wells it also acts as a modifier to the in-situ nature of the reservoir rock (Leontaritis et al. 1994). Typically the rock is changed from being water-wet to oil-wet resulting in preferential flow of water to the wells while the hydrocarbon is trapped back (Al-Maamari and Buckley 2003). The loss of producible reserves that could result from this phenomenon is also potentially very significant.OnePetroCHEVRONSPE106375Fluid DescriptionDownhole Fluid AnalysisAsphaltenesAsphaltene Gravitational Gradient in a Deepwater Reservoir as Determined by Downhole Fluid AnalysisOliver C. Mullins and Soraya S. Betancourt, Schlumberger-Doll Research; Myrt E. Cribbs and Jefferson L. Creek,Chevron Energy Technology Corp.; and Francois X. Dubost, A. Ballard Andrews, and Lalitha Venkataramanan, Schlumberger-Doll ResearchAbstract The fluids in large reservoirs can be in equilibrium - especially if conditions conducive to convective mixing prevail. A large vertical column of reservoir hydrocarbons offers a unique laboratory to investigate potential gravitational grading. Asphaltenes are known to exist in crude oils as a colloidal suspension but which had not been well characterized in the laboratory until recently. In this paper we review a gravitational gradient of asphaltenes in a reservoir and a simple theory is shown to apply. The corresponding downhole and laboratory analyses are consistent; asphaltenes exist in these crude oils in nanoaggregates. The corresponding asphaltene gradients provide a stringent and new method to test reservoir connectivity (as opposed to compartmentalization) which is key to the efficient economic development for many deepwater projects. Introduction In the past a presumption of fluid homogeneity in the reservoir prevailed. In part this assumption was made because dynamic calculations performed on reservoir models had difficulty accounting for any but the most basic of fluid compositional gradients. The conclusion followed if it cant be modeled why do I need to know about it? It turns out what you do not know can hurt you. There is a growing realization that fluids indeed are often heterogeneous in the reservoir;[1-3] this after all is earth science where little is homogenous. A variety of factors can lead to hydrocarbon compositional grading including gravity [4] thermal gradients [5] biodegradation [6] active charging water washing and leaky seals. Most of these mechanisms cause fluid disequilibrium in the reservoir and thus become very difficult to model. In addition reservoir compartmentalization leads to discontinuous compositional contrasts but in turn identifying these discontinuities may provide a means to identify compartments. Since many of these physics mechanisms that produce compositional variation are time dependent the existence of fluid distributions can depend on relative rates of fluid movement. Both convection and diffusion generally cause reservoir fluids to move towards equilibrium but at very different rates. Diffusion can be very slow across a reservoir (eg. ~100 MYr) many dynamic processes involving reservoir fluids will be faster.[7] On the other hand convection is fast (~1 MYr) thus if convection occurs oil columns can rapidly move towards equilibrium.[8] In high cost arenas such as areas of deepwater development one of the biggest impediments to unraveling fluid complexities in the reservoir is to obtain sufficient data. The new technology of Downhole Fluid Analysis (DFA) has proven very useful for the early identification of fluid gradients [9 10] and compartmentalization during the Exploration and Appraisal stage.[2 11] DFA is an objective and a vision ultimately to provide a continuous downhole fluid log; it is performed by specific tools such as the LFA (Live Fluid Analyzer) which performs spectral analysis of crude oils downhole immediately after removing the oil from the formation.CHEVRONIPTC12837Fluid DescriptionFluid TypingNMR InterpretationAccurate NMR Fluid Typing Using Functional T1/T2 Ratio and Fluid Component DecompositionBoqin Sun1, Mark Skalinski2, Jeroen. Brantjes3, Chengbin Liu1, Gerald A. LaTorraca4, Glenn Menard1, and Keh- Jim Dunn4 1Chevron Energy Technology Company. 2Tengizchevroil, 3Chevron International Exploration & Production Company, 4Chevron ConsultantAbstract Nuclear magnetic resonance (NMR) logging has been routinely used to measure mineralogy independent porosity irreducible water saturation and permeability of earth formation. The T2 distribution derived from NMR logging data is often composed of several fluid components. For example T2 of clay bound water is in general less than 10ms while T2 of movable water is above 33 ms in sandstone formation. Each fluid component can be represented by a unique T2 peak in a T2 distribution. The shape of the T2 peak can be predetermined by either a Gaussian or B-Spline function. Recently we have developed a Fluid Component Decomposition (FCD) method that uses a set of predetermined T2 peaks as base function to perform T2 inversion with CPMG echo trains. The FCD method significantly reduces the computation time for NMR data inversion especially for multi-dimensional data sets from oil well measurements without sacrificing the smoothness and accuracy of the inverted distributions. It also allows direct fluid typing from either raw CPMG echo data or apparent T2 distribution. We have applied FCD method for apparent heavy oil volume calculation to estimate in-situ heavy oil viscosity. One major uncertainty of both regular and FCD T2 inversion methods is T1/ T2 ratio. Reecent study shows that T1/T2 ratio is a linear function of T2 in log-log scale. We have applied this log-log function into FCD inversion code and greatly improve the accuracy of NMR total porosity in both carbonate formation and formations with large amount of paramagnetic impurity.CHEVRONSPE99386Fluid DescriptionInsitu PVT VariationsGas CondensateHow Reliable Is Fluid Gradient in Gas/Condensate Reservoirs?C.S. Kabir, SPE, Chevron ETC, and J.J. Pop, SPE, SchlumbergerAbstract Collection and analysis of gas/condensate fluid samples present considerable challenges. That is because downhole sampling of a gas/condensate fluid unlike its oil counterpart does not guarantee retrieval of single-phase fluid. The same is true for surface sampling because of incomplete surface and/or downhole separation. Given this reality the PVT analysis of any fluid sample with an equation-of-state (EOS) model demands that the results are verified with independent measurements. Our analyses of many samples show that a good correspondence exists between the PVT-derived gradient and that obtained from wellbore-flow modeling of production-test data. Older generation formation testers those prior to 1990 although yielding comparable results had larger error bars owing to system limitations in repeatability of both pressure and depth measurements. We developed a yield-temperature correlation to fill in the information void for reservoirs that fall within the bounds of measured data over a large geographic area. Correlating CO2 with formation temperature was a stepping stone to the yield/temperature relationship. This approach is applicable for the analysis of both single-reservoir and multi-reservoir samples which is particularly useful when rapid assessment is needed over large regions. Introduction The presence of a compositional gradient in reservoirs containing hydrocarbon columns has long been recognized since Sage and Lacey (1939) published their seminal work. Segregation of asphaltenes causes compositional grading in oil (20-30 API) columns. In contrast compositional grading in light-hydrocarbon (> 35 API) columns occurs for near-critical fluids or more appropriately for fluids close to the spinodal curve (Lira-Galeana 1992). Equilibrium between gravitational and chemical forces of various hydrocarbon components results in a variable saturation pressure in a fluid column (Schulte 1980; Riemens et al. 1988; Wheaton 1991). According to Hirschberg (1988) the time to reach such equilibrium (10 million to 1 billion years) is comparable to the geologic time of a typical reservoir. A number of authors have reported field experiences with compositional grading in gas/condensate reservoirs (Creek and Schrader 1985; Smith et al. 2000; Ghorayeb et al. 2003). Ordinarily the equilibrium approach appears to explain gradients observed in the field. In reality however heat flux can potentially prevent attaining true equilibrium in a hydrocarbon column owing to temperature gradient in a reservoir (Pedersen and Lindeloff 2003; Hoier and Whitson 2001; Ghorayeb and Firoozabadi 2000; Firoozabadi 1999). Irreversible thermodynamics appears to explain compositional grading in most systems. In this study we will assume that thermal diffusion does not play a dominant role in distributing hydrocarbon components in the fluid columns studied. As discussed depth-dependent fluid property variation has been shown to occur by discerning PVT properties (Hanafy and Mahgoub 2005; Smith et al. 2004; Montel et al. 2003). However direct comparison of independent measurements contributing to fluid gradients has been rare. The principal objective of this study is to compare fluid gradients from three different sources to seek consistency en route to establishing liquid content in gas/condensate systems. These independent sources include (1) EOS-model-derived compositional grading (2) spot pressures measured by wireline formation testers and (3) wellbore static gradient from a dynamically calibrated drillstem test (DST) data. Case Studies Spot pressures and the attendant fluid gradients derived from wireline formation testers (FT) are invaluable to all earth scientists and engineers alike. While the ability of formation testers to reveal fluid gradients is seldom questioned we probe whether fluid gradients of sufficient accuracy can be discerned to yield reliable liquid content in gas-condensate systems. In this study besides FT we examined two other sources of fluid gradient information; compositional gradients based on EOS models and the static-fluid gradient obtained from a calibrated wellbore flow model. The compositional gradient is obtained after tuning an EOS model and the wellbore model is calibrated with DST flowing pressures and temperatures at both bottomhole and wellhead. Note that all the necessary ingredients such as surface rates of both phases pressures and temperatures at both wellhead and sandface are available from a DST.CHEVRONSPE125203Fluid DescriptionProduction ChemistryAsphaltenesVerification of Asphaltene-Instability-Trend (ASIST) Predictions for Low-Molecular-Weight AlkanesJefferson L. Creek and Jianxin Wang, Chevron Energy Technology Company, and Jill S. Buckley, New Mexico TechSummary Anticipating when and where asphaltenes may flocculate during oil production is a key step in successfully preventing or mitigating asphaltene problems in the field. Because there will be no deposition without precipitation mapping of asphaltene stability over a wide range of temperature pressure and composition is required. The asphaltene-instability-trend (ASIST) allows the determination of the onset of asphaltene instability to be established with a series of liquid n-alkanes. These data are used to predict asphaltene stability of live fluids by extrapolating the onset condition from the base data to reservoir conditions by use of a linear extrapolation of the onset solubility parameter vs. square root of the partial molar volume of the precipitant. This extrapolation has been demonstrated previously to be accurate for methane and a model oil. The present work verifies that such an extrapolation is valid for predicting the asphaltene instability for mixtures of methane ethane and propane with a representative stock-tank oil (STO). The STO was combined with known amounts