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

TOTALOrganisationSourcePaper No.ChapterSectionSubjectTitleAuthorAbstractTOTALIPTC11737CO2Capture/StorageCase StudyThe CO2 Pilot at Lacq: An Integrated Oxycombustion CO2 Capture and Geological Storage Project in the South West of FranceNicolas Aimard, Total; Marc Lescanne, Total; Grard Mouronval, Total; Claude Prbende, TotalAbstract For decades to come oil and gas will remain an energy source of choice to meet increasing demand. But oil and gas operators have to develop fields requiring much more processing and energy - i.e. very sour gases or extra heavy oils - while reducing the Green House Gases (GHG) emissions to mitigate the climate change consequences. Among the possible options carbon capture and geological storage (CCS) appears to be a promising option in addition to power efficiency increase or renewable energies use. Total launched end 2006 an integrated CCS project in the South-West of France. It entails the conversion of a steam boiler into an oxy-fuel combustion unit oxygen being used for combustion rather than air to obtain a more concentrated CO2 stream easier to capture. The pilot plant which will produce some 40 t/h of steam for use other facilities will emit up to 150 000 tons of CO2 over a 2-year period which will be compressed and conveyed via pipeline to a depleted gas field 30 kilometers away where to be injected into a deep carbonate reservoir. CO2 injection is scheduled to begin end 2008. The paper presents the characteristics of the 30MWth oxyboiler one of the world first industrial oxy-combustion units. Then it focuses on the critical issues that can be addressed with an integrated project of combustion CO2 injection into a geological formation: CO2 purity level required by each element of the CCS chain validation of CO2 injection and migration models and validation of the methodologies put in place to assess well and storage integrity. It discusses the potential application among others of such technology in an extra heavy oil hot production" scheme with emphasis on the benefits to integrate all aspects of the CCS chain mentioned above for future large scale applications. Introduction For decades to come oil and gas will remain an energy source of choice to meet increasing demand. But oil and gas operators have to develop fields requiring much more processing and energy - i.e. very sour gases or extra heavy oils - while reducing the Green House Gases (GHG) emissions to mitigate the climate change consequences. Among the possible options carbon capture and geological storage (CCS) is an important option for tackling greenhouse gases emissions. In their 2007 summary report for policy makers on Mitigation of Climate Change1 the Intergovernmental Panel on Climate Change (IPCC) describes this option as one of the key mitigation technologies and practices currently available. While the worldwide CO2 atmospheric emission was around 30 billion tonnes in 20052 CO2 geological storage capacity could be very significant: 600-1 200 billion tonnes in oil and gas depleted fields 3-200 billion tonnes in unmineable coal seams and up to 1 000-10 000 billion tonnes in deep saline formations2. This represents between 70 and 500 years of storage at current production rates. But to ensure that CCS technology will be reliable on short and long term energy efficient accepted by the public and commercially viable industrial pilot plants are necessary. Total launched end 2006 an integrated CCS project in the South-West of France. It entails the conversion of a steam boiler into an oxy-fuel combustion unit oxygen being used for combustion rather than air to obtain a more concentrated CO2 stream easier to capture. The pilot plant which will produce some 40 t/h of steam for use other facilities will emit up to 150 000 tons of CO2 over a 2-year period at the Lacq existing facilities. Then the CO2 will be treated compressed and conveyed via pipeline to the depleted gas field named Rousse 30 kilometers away where to be injected into a deep carbonate reservoir as shown on Figure 1."OnePetroOnePetroTOTALSPE113353CO2Mechanism - Capillary AlterationCapillary Alteration of Caprocks by Acid GasesVirenkumar Shah, University of Pau and TOTAL SA; Daniel Broseta, University of Pau; and Gerard Mouronval, TOTAL SAAbstract The safety of acid gas geological storage is to a large extent controlled by the capillary properties of the caprock. This low-permeable (e.g. clayey) porous media usually saturated with water acts as a capillary barrier to the underlying stored acid gas provided its water-wettability is preserved and water/acid gas interfacial tension (IFT) is high enough. The displacement or capillary breakthrough pressure above which the stored acid gas intrudes into the caprock is directly related to those two interfacial properties. Water/acid gas IFTs have recently been thoroughly characterized. However little is known on the effect of acid gases (CO2 H2S and their mixtures) on the water-wettability of caprocks. We present an experimental setup and procedure for measuring contact angles on mineral substrates in the conditions of geological storage. Measurements have been carried out in a range of pressures extending up to 150 bar both with CO2 and H2S and with mineral substrates representative of caprock minerals such as quartz and mica as well as with a substrate sampled from the caprock of a depleted gas reservoir. We observed that the wettability alteration of mica is moderate in the presence of dense CO2 but pronounced in the presence of dense H2S. In contrast the wettability of quartz and of the real caprock substrate is not altered by dense CO2 or H2S. In addition to those substrate- and acid gas-dependent wettability effects the much lower water/acid gas IFTs as compared to water/hydrocarbon gas IFTs are responsible for a loss in capillary-sealing potential of a given caprock when a hydrocarbon gas is replaced with acid gas especially when the acid gas is rich in H2S. This potential as evaluated by the displacement or capillary breakthrough pressure should be determined very carefully when planning an acid gas geological storage operation. 1. Introduction As an increasing number of H2S-containing (sour) gas reservoirs are being exploited around the world there is a growing interest for injecting and storing in geological formations the H2S rich-acid gas that is separated from the (sour) natural gas in gas processing plants. For instance acid gas disposal in geological formations has been practised over the past 15 years in Western Canada where more than 3 Mt of H2S and 3 Mt of CO2 have been injected with a maximum up to 83% of H2S in one of the 40 storage sites (deep aquifers or depleted hydrocarbon reservoirs; Bachu 2007). The reinjection of H2S-rich acid gases in massive quantities is currently being considered in some reservoirs such as the Kashagan oil field in the North Caspian Sea. These reservoirs usually contain CO2 along with H2S as associated gases which are both separated in the gas plant. The injection of the resulting acid gas stream in a geological formation is interesting for the two following reasons: i) to avoid atmospheric emissions of CO2 and ii) to avoid H2S desulphurization through the Claus process which has many drawbacks both environmental and economical (Abou-Sayed et al. 2005). The implementation of this option on a large scale requires a proper assessment of the effects induced by the presence of acid gas on the integrity of the formation. This assessment is the subject of many research studies mostly conducted in the context of CO2 geological storage. A large part of this effort addresses the different possible leakage mechanisms by which CO2 may escape from the geological formation where it is stored.This effort needs to be extended to acid gases containing significant amounts of H2S.TOTALSPE109739CO2StorageMineralizationA Modeling Study of the Role of Selected Minerals in Enhancing CO2 Mineralization During CO2 Aquifer StorageS. Thibeau, Total; L.X. Nghiem, Computer Modelling Group; and H. Ohkuma, Japan Oil Engineering CompanyAbstract CO2 mineralization is a process whereby the CO2 that is injected into a geological formation dissolves into the formation water reacts with the in situ minerals and ions and precipitates as carbonate minerals. This process governs the long-term fate of the injected CO2 and ensures a safe storage once CO2 has been converted into minerals. In a previous study involving the modelling of the long-term fate of CO2 in the Utsira aquifer storage the authors observed that CO2 mineralization was not possible if mineral reactions were limited to Calcite and Dolomite precipitation and dissolution. Indeed to mineralize CO2 non carbonate minerals that are present in the formation have to: dissolve in order to buffer the pH decrease resulting from the CO2 injection; provide cations such as Ca2+ Mg2+ Fe2+ to the formation water; not release bicarbonate (HCO3) to the formation water. Then the released cations react with HCO3 resulting from the dissolution of the injected CO2 and precipitate new carbonate minerals. In this study the CO2 mineralization process is modelled taking into consideration various possible reactive pathways. In the first step the different reactive pathways are investigated in terms of reactive potential CO2 mineralization potential and consequences on the porous network. In the second step simulation of flow and dissolution of CO2 together with geochemical reactions is performed to examine the mineralization process in space and time for two different time scales: 1000 years with a finer grid to examine how chemistry interacts with the CO2 dissolution process; and 18 000 years with a coarser scale to reach geochemical equilibrium in the aquifer. This work shows that a limited amount of non-carbonate reactive minerals (for a given time scale) can contribute to the mineralization of CO2 that is significant for an industrial CO2 storage project. As such the identification of the reactive pathways leading to CO2 mineralization is a key step to evaluate the long-term fate of the injected CO2 in a geological storage project. Introduction Geological storage of CO2 is an important option for tackling greenhouse gases emissions. In their 2007 summary report for policy makers on Mitigation of Climate Change1 the Intergovernmental Panel on Climate Change (IPCC) describes this option as one of the key mitigation technologies and practices currently commercially available. Among the geological storage options CO2 storage in saline aquifers appears to be the most promising option in terms of worldwide CO2 storage capacity. This capacity was estimated to be between 1000 and 10 000 billion tonnes of CO22. For comparison purposes the worldwide CO2 atmospheric emission was around 30 billion tonnes in 20041. To ensure that CO2 will remain safely stored in aquifers in the long term it is necessary to model the fate of CO2 and its impact on the aquifer. Basic processes are CO2 dissolution into the formation water CO2 speciation into HCO3 and H+ (the latter acidizes the water) and mineralization. CO2 mineralization is the result of chemical reactions between HCO3 and other ions which precipitate new carbonate minerals. This process controls the long-term fate of CO2 as it consumes CO2 from the aqueous phase and results in a safe storage of CO2 as carbonate (solid) minerals. The world largest CO2 aquifer storage operation is ongoing at Sleipner in the Norwegian sector of the North Sea. Injection started in 1996 with more than 8 million tonnes of CO2 injected by mid 20063. In a previous work4 the long-term fate of the CO2 injected into the Utsira aquifer was modelled using a two-phase (gas-water) simulator with implicit coupling of convective and diffusive transport and geochemical reactions. Due to the selection of the reactive pathways which involve carbonate minerals initially present in the sandstone CO2 mineralization did not occur. The objective of this study is to model the CO2 mineralization process based on three key reactive pathways controlled by either calcium or magnesium or iron.TOTALIPTC12545Corporate ProcessTotal's Digital FieldHow To Handle Real-Life Well Production Instabilities and Uncertainties Within Digital Fields" A Practical Application From Congo and Gabon"Jacques Danquigny and Marc Tison, TOTAL; Guennol Ouay and Emmanuel Sgui, TOTAL E&P Congo; and Michel Vi, TOTAL GabonAbstract Digital fields involve the regular use of modeling tools to model and optimize production systems. Modeling is a challenge given the transient and instable flow regimes encountered in Oil & Gas facilities. Optimization requires a further level of accuracy: it implies the modeling of an envelope of production operating-points. This paper presents the solutions which are being implemented in two affiliates of West Africa within TOTAL Digital Field corporate program called Field Monitoring to address this issue. The instabilities of production parameters observed during production tests are assessed for gas-lifted wells in Total Congo and Gabon affiliates. These tests are systematically modeled with nodal well flow models. The impact of well instabilities or metering and reservoir uncertainties on modeled outputs such as gross production rates is assessed. This enables to better check the quality of production tests or the need to question or update the model of a well. This study highlights the parameters which have the main influence on well models outputs. It shows the accuracy of these models which can also be used to carry out virtual flow metering. It provides guidelines on how to keep well flow models updated which is a key issue to sustain real-time production optimization tools. The conclusions of this study are now implemented in TOTAL Congo and Gabon affiliates as a positive part of the change management involved in Digital Fields implementations to monitor and optimize the performance of production wells. Introduction To address the challenge of production optimization on a daily or even real time frequency many oil companies are strongly involved in the development of Digital Fields technology. Total is one of them. It has developed a fit-for-purpose tool which was installed as a pilot on the mature field in Congo (ref. 1). This tool called WPM standing for Well Performance Monitoring is being industrialized and deployed at a corporate level. This tool is providing data visualization tools a first-class alarming system. Some of these alarms are based on modeling by well flow model PROSPER. One of the workflow is the automatic modeling of production test. Figure 1 is showing its logigram; WPM detects automatically new production tests in the corporate Production Dabase Management System (noted PDMS). Downloading the averaged results of the tests from PDMS and from the Reservoir Database (the OFM software) the reservoir static pressure and the productivity index of the well WPM models the test with PROSPER using two computation techniques System Calculation and Quick-Look described in the following paragraphs. For each OUTPUT the difference between the modeled data and the actual average test data is computed. As soon as this difference is greater than a specified cut-off an alarm is triggered. On a theoretical point of view this approach implies implicitly that well flow models are linear which is not true: the OUTPUTs computed with the averages of the INPUTs are not equal to the average of the OUTPUTs which would be computed with real-time data INPUTs.TOTALIPTC12106Corporate ProcessTotal's Knowledge ManagementIntegrated Data and Information Management System From SubSurface to Surface to Enhance Production Activity and Business DecisionDriving Cross Disciplines Integration Through Data/Information ManagementTati Magdalena SAHEA, SPE, Nyoman SWATIKA, SPE, and Renaldy, SPE, Total E&P IndonesieExtended Abstract Today knowledge has power. It controls access to opportunity and advancement. -- Peter F. Drucker Today it is so often we heard the words of data or information.Furthermore it becomesthe data or information management process where three important parts should be involved: input process output. From those three data become the input and running systems or applications are the processes which will deliver information as the output. Those three basic parts are essential for running continuously and simultaneously in a daily operation by implementing the data or information management system practices within the company. For Total E&P Indonesie the beginning of Data/Information Management project (dedicated for Geoscience and Reservoir division) had been carried out in the year 2000 and was successfully completed in 2003. Today its Geoscience and Reservoir division has applied an integrated data and information management practices starting from subsurface activities (well and reservoir production data) to surface facilities (production and/or process data (eithier non-realtime or realtime data capture methods) by having Geoscience Data Management (GaDaMa) and Production Data Management System (PDMS). A unique data or information management system was implemented by integrating Information/Data Management tools (i.e. Web Based Application 1).DecisionPoint MS Excell etc) as an interface for reporting and data accessing to geosciences and production databases. Data entry is carried out either manually through MS-Excell and Web-based application gadgets or automatically captured with source of data from Distributed Control System (DCS) on several sites. Integrating PDMS into a new Plant Information Real Time Data Management (2)PI-RTDB) deployed in Total E&P Indonesie is underway to enable auto-capturing of high frequency data mainly on well flowline paramaters. Thus a daily and integrated Geoscience Data Management and Production Data Management System Workflows are now uniquely operating in Total E&P Indonesie. Different entities (geologist petrophysic reservoir and production sites) within the division have been taking full benefits of the implementation of data and information management. QC and validation before loading data into corporate database has been applied by entities using a Web-based application (Decision Point) or manually by other applications (i.e. 3)Geolog6 and MS-Office).TOTALSPE112517Corporate ProcessTotal's Knowledge ManagementTransforming E&P Data Into Knowledge: Applications of an Integration StrategyJean-Paul Couput, Alain Louis, and Jacques Danquigny, TOTAL S.A.Abstract The full added value of a field performance strategy is only achieved when every effort is treated as an integral part of the complete and larger production system which ranges from reservoir to export. By combining data gathering integrated modelling and control elements in so-called value loops optimization opportunities of the field efficiency are achieved in every phase of the asset lifecycle. The Field Monitoring solutions of TOTAL aim at improving this field performance through the execution of pertinent analyses that help take strategic decisions; these decisions are based on a common single and widely shared view of the information that provides a better understanding of ongoing events on each asset. This paper presents TOTAL field examples of Data Validation and Reconciliation (DVR) applied to flow measurement (metering) systems; and the resulting added value : in improving production allocation along with reservoir and surface material balance in reconciling surface and subsurface monitoring for production and reserves optimization. It evidences in particular : That DVR implementation associated with flow modelling improves the reliability and accuracy of the production estimates and of the subsea and downhole measurement devices The high potential of DVR in analyzing qualifying and interpretating large amounts of measurements and in providing more information from existing sensors which is of particular interest when key measurements fail or are non available Introduction The main objective of the digital oilfield concept is to maximize production and recovery by integrating the production operations from the reservoir to export and by using the suitable models and optimization techniques. The combination of both existing and leading-edge technologies ensures to constantly reach the field optimal efficiency. Today most of the production systems require accurate raw production data. All measured data contains various types of errors : intrinsic measurement errors gross errors noise . Moreover when real time measuring systems such as multiphase flow meters are used errors may originate from the inaccuracy of the model used to compute the flow rates of the individual phases. Basing operating decisions on such data may directly impact the reserves calculations computed from a wrong material balance using such back allocation volumes. The traditional approach to overcome these issues by combining best practices and measurement devices is not sufficient any longer. In the upstream activity new sensor technologies including three-phase metering and virtual metering have emerged. They still remain a challenge especially in deepwater subsea applications where the repair or the replacement of equipment involves huge costs. One solution is to combine physical measurement data coming from physical sensors with with virtual metering and Data Validation and Reconciliation models. This is an innovative approach that has been proven in the downstream area and that effectively helps increase oil production and recovery. Data quality issues Building strong and robust field monitoring systems assumes that the right and correct measurement and data are made available for further processing at the right time . This constitutes a real challenge for existing and upcoming installations in the upstream area where both instrumentation and associated measurements are subject to deficiency and inconsistency. Another issue is the lack of measurement in case of failure or simply in case of simplified measurement systems designed with minimum equipment.TOTALIPTC12658DrillingLight Well ArchitectureTunu FieldTunu Field Light Architecture WellsPh. Jeannet, Ch. Longis, M. Caroline, F. Widiwibowo, G. Tarnaud, D. Dodiono, and L. Vervynck, Total E&P IndonesieAbstract One of the challenges of the mature Tunu giant gas and condensate field development is the size reduction of new reserves associated to each new target which tends to reduce the economical value of future drilling projects especially in a context of increasing services prices. To allow maintaining a production plateau of the field currently sustained by intensive infill drilling and perforation activity an innovative light architecture well solution is being implemented to help reduce drilling costs. More than 500 development wells have already been drilled on Tunu field since1991 to produce multi-layered reservoirs deposited in deltaic environment down to 4 500 mSS. One of the main drilling challenges resides in developing some of the reservoirs located underneath pressurised shales which imply to design multi-phased wells. Efforts were put together to design light architecture wells within technical drilling limits to produce those reservoirs without compromising the SAFETY of the drilling operations. The result of the detailed engineering studies was to drill and complete wells to a maximum 4 200 mSS 1 500 m departure with only one driven Conductor Pipe one combined surface intermediate and production casing and one tubingless completion string. This yields to an average 30% savings on cost and duration. This has been made possible thanks to a joint effort of both geosciences and drilling teams. A comprehensive mapping of the low pressure zones along with significant observed production has allowed defining the areas where light architecture wells could be proposed without jeopardizing well deliverability and ultimate reserves of the field. The next step is to increase the percentage of light architecture wells to continue the development of Tunu field by challenging the technical drilling limits as well as maximising the target candidates for light well architecture.OnePetroTOTALSPE116672EOR/IORPolymer InjectionCase StudyPolymer Injection in Deep Offshore Field: The Dalia Angola CaseD. Morel, M. Vert, Total E&P, S. Jouenne, Total Petrochemicals France, E. Nahas, Total E&PAbstract Whereas on-shore polymer injection may be qualified as a mature EOR technique considering the hundreds of operations that have been conducted all over the world only one polymer pilot has been implemented offshore and none in deep offshore conditions. A very thorough feasibility study of polymer injection has been made on the Dalia field in Angola a typical deep-offshore high permeability (>1D as an average) sandstone reservoir containing medium viscosity oil (3 to 7cP under reservoir conditions). The study has demonstrated that high molecular weight hydrolyzed polyacrylamides could be used under a wide range of salinities covering sea water and a mixture of sea water and produced water. Additional recoveries in the range of 3 to 7 % can be expected in this particular context of large well-spacing development of a medium viscosity field. Powder polymer supply is achievable for deep offshore fields either with a specific bulk carrier or using standard international containers to transport big bags (750 kg). Although the on-deck option is simpler even in the case where no room is left on the existing FPSO marine options can be found to safely process the polymer on a barge connected to the FPSO (depending on the sea conditions) but the on-deck option is more simple. The need for an injectivity pilot is compulsory to demonstrate the operability of the facilities and the injectivity of the polymer solution. A single well test has been designed and is planned fall 2008 in Luanda on one of the well of the Camelia reservoir. A skid dedicated to the injectivity test has been designed assembled and constructed to prepare a mother solution of polymer from powder. Tested in France (no injection) the skid has been shipped to Luanda for installation on the FPSO during summer 2008. Future of the project will depend on the injectivity tests results and on-going studies on a phased approach. Introduction Deep offshore reservoirs may be good candidates for EOR by polymer injection : they are generally shallow (below sea floor) which means rather low temperature; waterflooding is the preferred basic recovery mechanism for pressure maintenance and sweeping; very often the reservoir oil is rather viscous as a result of biodegradation which has occurred due to temperature conditions; recovery by water injection is then adversely affected by an unfavourable mobility ratio and can be improved by injecting viscosified water; the reservoirs are often turbidites of very good characteristics allowing an efficient propagation of high molecular weight polymers; the wells are quite prolific for both production and injection; injecting a viscous solution should not be an issue. Despite this long list of positive criteria there is still no implementation of polymer injection in deep offshore conditions and only two small off shore pilot operation [1-2] whereas on-shore polymer injection may be qualified as a mature EOR technique when considering the hundreds of operations that have been conducted all over the world. Several key issues have to be faced in deep offshore that are a major step out versus existing commercial onshore projects: the range of salinities to be met over field life particularly if sea water is to be injected (most existing - on shore- projects are injecting almost fresh water) the larger well spacing: typically 500m to 1500m instead of 150m to 400m the facilities: multi-well injection through common subsea lines FPSO with no/reduced room for additional facilities the logistics to ship the polymer the incremental oil evaluation in fields with little to no water injection historyTOTALIPTC11800EOR/IORPolymer InjectionOffshore ImplementationFeasibility Study for EOR by Polymer Injection In Deep Offshore FieldsD.Morel, A.Labastie, Total E&P, S.Jouenne Total Petrochemicals France, E. Nahas Total E&PAbstract Whereas on-shore polymer injection may be qualified as a mature EOR technique considering the hundreds of operations that have been conducted all over the world only one polymer pilot has been implemented offshore and none in deep offshore conditions. A very thorough feasibility study of polymer injection has been made on a typical deep-offshore high permeability (>1D as an average) sandstone reservoir containing medium viscosity oil (3 to 7cP under reservoir conditions). The study has demonstrated that high molecular weight hydrolyzed polyacrylamides could be used under a wide range of salinities covering sea water and a mixture of sea water and produced water. Additional recoveries in the range of 5% can be achieved in this particular context of large well-spacing development of a medium viscosity field. Powder polymer supply is achievable for deep offshore fields either with a specific bulk carrier or using standard international containers to transport big bags (250 kg). Even in the case where no room is left on the existing FPSO marine options can be found to safely process the polymer on a barge connected to the FPSO (depending on the sea conditions) but the on-deck option is more simple. The need for an injectivity pilot is compulsory to demonstrate the operability of the facilities and the injectivity of the polymer solution The design of a pilot that would demonstrate the efficiency of the polymer is a more difficult and open question and may lead to a phased development as single well injection using a dedicated semi-submersible rig may be too expensive for a long duration. Introduction Deep offshore reservoirs may be good candidates for EOR by polymer injection: they are generally shallow (below sea floor) which means rather low temperature; waterflooding is the preferred basic recovery mechanism for pressure maintenance and sweeping; very often the reservoir oil is rather viscous as a result of biodegradation which has occurred due to temperature conditions; recovery by water injection is then adversely affected by an unfavourable mobility ratio and can be improved by injecting viscosified water; the reservoirs are often turbidites of very good characteristics allowing an efficient propagation of high molecular weight polymers; the wells are quite prolific for both production and injection; injecting a viscous solution should not be an issue. Despite this long list of positive criteria there is still no implementation of polymer injection in deep offshore conditions and only one single off shore pilot operation [1] whereas on-shore polymer injection may be qualified as a mature EOR technique when considering the hundreds of operations that were conducted all over the world. Several key issues have to be faced in deep offshore that are a major step out versus existing commercial onshore projects: the range of salinities to be met over field life particularly if sea water is to be injected (most existing -on shore- projects are injecting almost fresh water) the larger well spacing: 500m to 1500m instead of 150m to 400m the facilities: multi-well injection through common subsea lines FPSO with no/reduced room for additional facilities the logistics to ship the polymer the incremental oil evaluation in fields with little to no water injection history A very thorough feasibility study has been achieved on a typical deep offshore case which demonstrates that high molecular weight hydrolysed polyacrylamide may be used with sea water and produced water based on detailed simulation work large well spacing still brings significant additional oil powder polymer solution is viable offshore different options being still under further investigation (mainly HSE issues) including a compact skid to be added on the existing FPSO Realistic options can be proposed for the logistics to ship the polymer powder on site .TOTALSPE99546EOR/IORTechnologiesNorth Sea ExperienceA Survey of North Sea Enhanced-Oil-Recovery Projects Initiated During the Years 1975 to 2005A.R. Awan, SPE, NTNU/Total E&P Norge; R. Teigland, SPE, Total E&P Norge; and J. Kleppe, SPE, NTNUSummary This paper provides a summary and a guide of the enhanced-oil-recovery (EOR) technologies initiated in the North Sea in the period from 1975 until beginning of 2005. The five EOR technologies that have been initiated in this region are hydrocarbon (HC) miscible gas injection water-alternating-gas (WAG) injection injection simultaneous water-and-gas (SWAG) injection foam-assisted WAG (FAWAG) injection and microbial EOR (MEOR). Each EOR technology that has been initiated in the North Sea was identified with its respective maturity level and/or maturation time frame technology use restrictions and process efficiency on the basis of incremental oil. Apart from WAG at Ekofisk and FAWAG at Snorre central fault block (CFB) all technologies have been applied successfully (i.e. positive in economic terms) to the associated fields. HC miscible gas injection and WAG injection can be considered mature technologies in the North Sea. The most commonly used EOR technology in the North Sea has been WAG and it is recognized as the most successful EOR technology. The main problems experienced were injectivity (WAG SWAG and FAWAG projects) injection system monitoring and reservoir heterogeneities (HC miscible gas injection WAG SWAG and FAWAG projects). Approximately 63% of all the reported EOR field applications have been initiated on the Norwegian continental shelf (NCS) 32% on the UK continental shelf and the remainder on the Danish continental shelf. Statoil has been the leader in conducting EOR field applications in the North Sea. The majority of future research will concentrate on microbial processes CO2 injection and WAG (including SWAG) injection schemes. In this review laboratory techniques global statistics simulation tools and economical evaluation were not considered and are considered outside of the scope of this paper. Introduction In the North Sea current average recovery factors (Hughes 2004; Xia 2004; Hansen and Westvik 2000; Blaker et al. 2006) are above 40%. As of 2003 the estimated oil reserves (OG21 2006) on the NCS are approximately 3850 million sm3 translating to an average recovery factor of 45% as shown in Fig. 1. The Ministry of Petroleum and Energy of Norway established the OG21 Task Force in 2001 to address the challenge of targeting a 50% average oil recovery factor set by the Norwegian Petroleum Directorate (NPD). This will yield 600 million sm3 additional oil. Among other technologies EOR is one of the solutions to meet this goal. Since 1982 several major Norwegian increased-oil-recovery (IOR) programs (Hinderaker et al. 1996) as listed in Table 1 have been initiated for additional oil recovery. Approximately 50 million USD has been invested in these Norwegian research programs (19821995). In 2003 the Oil and Gas in the 21st Century (OG21 Task Force) identified nine technology target areas to obtain the average recovery factors of 50% for oil and 75% for gas on the NCS (Blaker et al. 2006). On the basis of the IOR potential for each method and an evaluation of the importance and complexity of the technology gap they proposed the following ranking of the different recovery methods: Priority 1: (a) HC gas injection WAG/SWAG and FAWAG; (b) CO2 flooding; and (c) MIOR. Priority 2: (a) waterflooding; (b) massive depressurization; and (c) air injection. Priority 3: (a) gas condensate; (b) water additives; and (c) N2 and flue-gas injection. Apart from these research programs it is important to review the EOR technologies that have been initiated in the North Sea. The application of EOR technologies in the North Sea environment is more complex than and quite different from onshore applications. Thus it is necessary to identify the applied EOR technologies in the North Sea with their respective maturity level technology use restrictions and process efficiency on the basis of incremental oil. The main objectives of this survey are to categorize the different EOR technologies initiated in the North Sea with respect to their respective maturity level to recognize important EOR related data such as reservoir fluid formation properties injection parameters and enhanced production. In addition we attempt to identify the EOR frontrunner in the North Sea by method technology location and company lessons learned/key issues regarding EOR processes in the North Sea and the EOR trend in the North Sea. We would also like to emphasize that this review is based purely upon open literature and therefore may lack some important data that are not accessible through this source. This review should be considered as a guide for the EOR technologies initiated in the North Sea.TOTALIPTC12131EOR/IORWell InterventionWater Shut-offTackling Gas Field Decline With Efficient Chemical Water Shut-off: Successful Application on Peciko Field (East Kalimantan, Indonesia)Armon Armon and Latief Riyanto, SPE, Total E&P IndonesieAbstract High water production in a gas well could significantly reduce gas production due to high friction losses in the tubing the effect of water blocking in front of perforations and formation damage due to water which eventually could lead to a significant loss of recoverable reserves. Selective mechanical water shut-off (i.e. casing patch) the main technique used to solve this problem so far has some disadvantages mainly reducing the inside diameter of the production tubing which makes future mechanical water shut-off of the deeper reservoirs more difficult. Chemical water shut-off is the preferred solution to this problem. Peciko is a giant multilayer gas field located in the Mahakam delta of East Kalimantan with water depths of around 30 40 meters. There are more than 100 reservoirs per well with average thicknesses of less than 1 m. Most of these reservoirs were perforated and produced commingled throughout the lifetime of a well. Efficient water shut-off is very critical when water breakthrough occurs at some of these reservoirs in order to optimize gas production from the other reservoirs. Production logging measurements are used to identify the water producing reservoir to be isolated. This paper presents a successful field application of chemical water shut-off at Peciko field. In this application the chemical water shut-off is the unique solution due to the thickness of the reservoir to be isolated (>8 m) not feasible using current mechanical techniques and the interest of keeping a full bore access to allow future mechanical water shut-off for the other deeper reservoirs while isolating the water source located above. Sealing quality at the isolated water zone was confirmed by a production logging job performed after the chemical water shut-off operation. This successful chemical water shut-off reduced the water production rate from 4 000 bwpd to less than 100 bwpd and allowed an instantaneous gas production gain of 10 MMscfd with an estimated cumulative gain of 10 Bscf in 3 years. Introduction Peciko is a giant offshore gas field in the Mahakam delta at East Kalimantan - Indonesia which covers an area of of 350 km2 with water depths of 30-40 meters. The field has multilayer pay zones at around 2 000 4 000 meters subsea with an unfaulted structure. The producing layers are in Upper Miocene formations with a mud dominated delta environment and thin sand stone reservoirs generally less than 1 meter in thickness. Due to the complexity of the field a phased development was applied in order to minimize the risk and to optimize the field production. 5 phases of development have already been performed to develop the field. There are around 100 development wells already drilled in Peciko located on 6 production platforms. The production was started at the end of 1999 with a peak production of around 1 400 MMscfd in 2005. The current gas production of the field is close to 1 000 MMscfd and the condensate to gas ratio is around 15 bbl condensate / MMscf gas. The well potentials currently range from 1 to 30 MMscfd of gas. A typical Peciko well is a deviated well of 20-60 degree deviation with 3 500 4 000 meters subsea total depth. Most of of the wells have a monobore completion with a production tubing size of 4.5 or 5.5(Figure-1). There are more than 50 sandstone reservoirs perforated in a well and production is commingled throughout the life time of a well. The main challenge in the monobore completion is to optimize production from gas reservoirs when water breakthrough has occurred from one of them. No selectivity options such as sleeves are available to enable the water producing reservoir to be shut off.TOTALSPE121182EOR/IORWell InterventionWater Shut-offSelective Water Shutoff in Gas Well Turns a Liability into an Asset: A Successful Case History From East Kalimantan, IndonesiaChat Junesompitsiri, Antoine Berel, and Richard Curtice, Halliburton, and Latief Riyanto, Etienne Thouvenin, and Pascal Cheneviere, Total E&P IndonesieAbstract This case history describes a procedure in which a polymer sealant and a bridge plug were used to shut off water production from upper zones to enable gas production from productive lower zones. Offshore gas fields operated in East Kalimantan were producing gas and water. When water production increased gas production was greatly reduced. This paper presents a case history of water-shutoff work performed in the Peciko field offshore East Kalimantan Indonesia. Typically the production of these wells is commingled with multiple perforations inside the production casing and the water breakthrough could happen at any layer; therefore a selective shutoff is required. A production-logging tool (PLT) was run to identify the source of the water influx and the uppermost set of perforations was identified to be the main contributor to the water production. The objective was to completely shut off the uppermost zones with sealant without a cement tail-in. The chosen sealant was an organically crosslinked polymer system and tail-in with a particle-gel system (PGS) to increase near-wellbore shutoff integrity. Because the target shutoff zone was the uppermost set of perforations a retrievable bridge plug was used to provide isolation from all the lower zones while pumping the sealant. The operation sequence consists of (1) setting the retrievable bridge plug (2) performing an injectivity test (3) pumping the sealants (4) shutting-in to allow the polymer to develop strength (5) cleaning out excess particle gel inside the wellbore (without milling) (6) retrieving the bridge plug in an underbalanced condition and then (7) flowing the well. The job was initially evaluated by flowing the well and observing the well performance. Later a PLT was run to confirm the amount of influx from the shutoff zone. Results from both were very satisfactory as is detailed in the paper. Introduction Peciko field is a giant gas field in the Mahakam delta for the operating company. The nature of the field has multilayer pay zones which lead to the monobore completion style of either 4.5-in. or 5.5-in. then all the zones are perforated and produced commingledly. The work performed was on one of the best candidate wells on the oldest platform in the field. The target zone is a 10 m thick (from 3 606 to 3 616 m) sandstone formation with a temperature of 234F 1 709 psi reservoir pressure and porosity of 21% with permeability ranging from 350 to 700 md with 500 md average (Fig. 1). In early January 2007 water breakthrough in the candidate well caused drastic increase in water production to 500 to 1 500 BWPD. The well was choked back and the PLT was run to identify sources of water influx. The results (Fig. 2) indicated that the majority of the water was contributed from the uppermost zone and the production was about 2 MMcf/D gas with 260 bwpd. The decision then was to perform a complete shutoff on that zone. Isolation Because the target interval is the uppermost interval the use of some sort of retrievable bridge plug must be considered to provide isolation from the rest of the productive zones below. An inflatable retrievable bridge plug (IRBP) was selected with several benefits to accommodate the placement as required by the well conditions.OnePetroTOTALSPE121544Flow AssuranceDrag Reducing AgentEvaluationExperimental Methodology to Evaluate DRA: Effect of Water Content and Waxes on Their EfficiencyI. Henaut, M. Darbouret, and T. Palermo, IFP, and P. Glenat and C. Hurtevent, TOTALAbstract Drag reducing agents are used to reduce significantly the frictional pressure loss under turbulent flow conditions allowing a substantial increase in pipeline capacity. Their performance is known to depend on their own characteristics (molecular weight structure chemical composition) and on external parameters such as turbulence intensity oil viscosity etc. The mechanism by which DRAs interfere with turbulence is not fully understood and drag reduction is not easy to predict. Laboratory tests are still required to quantify the potential efficiency of these additives. This paper reports on an original experimental methodology based on the combined use of a classical rheometer and a laboratory loop offering a large range of experimental conditions in terms of temperature pressure flow rates and cooling rates. Different commercial oil soluble DRAs have been tested on various fluids including a paraffinic crude oil. The experimental results have shown that either the presence of waxy crystals or emulsified water droplets can alter the DRA efficiency while they are not affected by waxy deposits or low temperature. 1. Introduction Drag reduction is defined as the reduction of skin friction in turbulent flow below that of the solvent alone [1]. This phenomenon also termed as Tom's effect has been shown to occur with the addition of small amounts of certain materials in various aqueous or organic liquids. These substances include surfactants fibers wood pulp and more generally macromolecules. They are named drag-reducing agents (DRAs) and have lead to many practical benefits in ship-building industries fire-fighting operations biomedical applications etc. This paper focuses on the use of polymeric drag-reducing agents in the oil industry. Actually oil soluble and long-chain polymers are known to reduce the frictional pressure drop caused by turbulence in a pipeline. As a result the operating pressure can be diminished while keeping the same flow rate or the throughput can be increased while applying the same pressure. In spite of extensive experimental studies and sophisticated simulations [2-6] the complex mechanism of polymeric drag reduction remains unclear. Its understanding is out of scope of the present paper. We only mention that polymer molecules are assumed to undergo a dynamic chain elongation that interacts with eddies in the flow altering the whole energy balance of the turbulence. This chain stretching occurs under high shear and explains why drag reduction is generally accepted as a near-wall phenomenon. As the action of the polymer is mainly located at the near-wall region only a few tens of parts per millions by weight of product are required. The low concentrations make these chemicals economically attractive. They are all the more easy to handle and are known to reduce the effect of diffusion controlled corrosion [7]. This drag reduction study is divided into two parts. The first one aims at evaluating the effectiveness of polymeric additives thanks to an original experimental methodology. It involves two complementary devices: a rheometer and a small-scale flow loop. Both apparatus are described in the experimental section of the paper with their respective procedures. The second part of this research program is dedicated to the effect of the transported crude oil on the performance of the DRA. Particular attention is paid on the influence of waxy crystals and emulsified water. 2. Experimental section 2.1 Chemicals Four different commercial DRAs provided by different chemical suppliers were tested. These DRAs are referred to as DRA 1 DRA 2 DRA 3 and DRA 4 hereafter. All these DRA are oil soluble long-chain polymers. They were used as such.TOTALIPTC11379Flow AssuranceProduction ModellingGirassol Deepwater FieldA Systematic Investigation of Girassol Deepwater Field Operational Data to Increase Confidence in Multiphase SimulationErich Zakarian and Dominique Larrey, TotalAbstract After over 5 years experience as operator of Girassol the earliest deepwater field put in production offshore West Africa Total has recorded a large amount of operational data. The production system includes several conventional subsea loops connected to a FPSO by 1350m water depth with gas lift injected at the bottom of the risers for activation and flow stabilization. A systematic review of the operating parameters of the subsea production loops over the past years gave the opportunity to extract series of measurements representative of a wide range of flow rates water-cuts gas-lift rates including flow stability tests performed both on upward and downward sloping flowlines. These data were compared to the results obtained from dynamic simulations performed with the simulation code OLGA2000 originally used for the design of the subsea production system. The comparison focused on the overall pressure drop between manifolds and topside and on the transition between stable and unstable flow with decreasing gas lift rate. The work was conducted in two steps first updating the model of each flowline to implement the details of the as-built geometry then performing extensive numerical simulations and post-processing of the selected operational cases. Particular attention was paid to the first step in order to achieve the best compromise between model accuracy and computational speed. The optimum was met when the model run with the Slug Tracking option was able to reproduce the transition to unstable flow observed on site. In order to investigate future operating conditions of the Girassol field this methodology will help to establish a confidence level in multiphase simulation. This work can also serve as a reference for other deepwater field developments. The Girassol field Girassol is a deepwater oil field development located 210km northwest of Luanda in Angola and about 150 km from shore [1]. The reservoir is shallow (1 200 m) with a large horizontal extent: pressure and temperature are about 250 bar and 70C respectively. The oil has an API gravity of approximately 32 and the GOR is in order of 110-130 Sm3/Sm3. Production from the field is tied-back to a FPSO through 8'' I.D. piggable production loops: cf. Figure 1. The 24 production wells are connected to the production loops through 2-slot manifolds at a maximum 6km distance. They are equipped for chemical injection continuously at downhole and possibly at Christmas tree for batch treatments. Flow assurance issues such as wax deposition or hydrate formation are primarily covered during normal production operations by an extensive thermal insulation of the subsea production system (SPS) [2]. Thermal performance is achieved with the gathering of the production flowlines (right and left lines of a production loop) within seabed bundles and riser towers (two production loops per riser tower). During shut-down conditions the full SPS is designed to be preserved from hydrate formation (after a no-touch time) through: methanol injection at wellheads jumpers and manifolds from 2 service lines; displacement of live oil with (stabilised) dead oil circulation from the FPSO into the production loops. Gas-lift can be injected at the base of the production risers for activation and flow stabilization.OnePetroTOTALSPE123111Flow AssuranceProduction ModellingGirassol Deepwater FieldA Systematic Investigation of Girassol Deepwater-Field Operational Data To Increase Confidence in Multiphase SimulationErich Zakarian and Dominique Larrey, TotalSummary After more than 5 years of experience as operator of Girassol the earliest deepwater field put in production offshore West Africa Total has recorded a large amount of operational data. The production system includes several conventional subsea loops connected to a floating-production storage and offloading vessel (FPSO) at 1 350-m water depth with gas lift injected at the bottom of the risers for activation and flow stabilization. A systematic review of the operating parameters of the subsea production loops over the past years gave the opportunity to extract series of measurements representative of a wide range of flow rates watercuts and gas-lift rates including flow-stability tests performed both on upward- and downward-sloping flowlines. These data were compared to the results obtained from dynamic simulations performed with the simulation code OLGA originally used for the design of the subsea production system. The comparison focused on the overall pressure drop between manifolds and topside and on the transition between stable and unstable flow with decreasing gas lift rate. The work was conducted in two steps. First updating the model of each flowline to implement the details of the as-built geometry then performing extensive numerical simulations and post-processing of the selected operational cases. Particular attention was paid to the first step to achieve the best compromise between model accuracy and computation speed. The optimum was met when the model run with the Slug Tracking option was able to reproduce the transition to unstable flow observed onsite. To investigate future operating conditions of the Girassol field this methodology will help to establish a confidence level in multiphase simulation. This work can also serve as a reference for other deepwater-field developments.TOTALSPE121484Fluid DescriptionCorrelationsHP Acid gasHigh Pressure Acid Gas Viscosity CorrelationG. Galliro, C. Boned and A. Baylaucq, LFC with CNRS, Pau University; and F. Montel, SPE, TOTALAbstract Acid gases containing H2S are often encountered in the petroleum industry. However reliable experiments on their thermophysical properties in reservoir conditions in particular viscosity are very scarce. From a modeling point of view H2S (and CO2) are polar compounds and are so often considered as rather difficult to model accurately. In this work we propose a correlation based on a corresponding states approach in order to predict the viscosity of acid gas mixtures among others with a strong physical background. This correlation is based on the Lennard-Jones fluid model which has been studied extensively thanks to molecular dynamics simulations over a wide range of thermodynamic conditions. This fluid model can be extended to deal with polar molecules such as CO2 or H2S without a loss of accuracy. In a first part we demonstrate that the proposed physically based correlation is able to provide an excellent estimation of the viscosity (with average absolute deviations below 5 %) of pure compounds including normal-alkanes CO2 or even H2S whatever the thermodynamic conditions gas liquid or supercritical. Then using a one-fluid approximation and a set of combining rules the correlation is applied to various mixtures in a fully predictive way i.e. without any additional fitted parameters. Using this scheme the deviations between predictions and measurements are as low as on pure fluids. The viscosity of natural and acid gas mixtures in reservoir conditions is shown to be very well predicted by the proposed scheme. In addition it is shown that this correlation can also be applied to predict reasonably the viscosity of asymmetric high pressures mixtures even in the liquid phase. This physically based approach is easy to plug in any simulation software as long as the only inputs the molecular parameters are directly related to the critical temperature and volume. Introduction Natural gases containing carbon dioxide and/or hydrogen sulfide the so-called acid gases are often encountered in the petroleum industry (Ungerer et al. 2005). Nevertheless reliable experiments on their thermophysical properties are very scarce. In the case of hydrogen sulfide there are practically no data because of its high toxicity. This lack of information is even more pronounced concerning transport properties such as the viscosity (Galliro and Boned 2008; Liley et al. 1998; Schmidt et al. 2008) at typical petroleum reservoir conditions i.e. high pressures and high temperatures. A predictive physically based model is highly required as long as high pressure viscosity is one of the key physical properties for the design of acid gases disposal. Molecular simulation which can be considered as a numerical experiment on a model fluid is one of the valuable alternatives to experiments to gather physical information on such systems of interest. Using this simulation technique allows to obtain exact result on a molecular model representing the fluid studied without any limitations on the state studied. It has been shown that such an approach is efficient to describe the thermophysical properties of fluids such as acid gas mixtures (Galliro et al. 2007 Ungerer et al. 2005). Nevertheless molecular simulations technique require a rather long time to obtain result (around one day of simulation for one point) and so cannot be yet easily used routinely from an engineering point of view. In order to circumvent this problem it is possible to use the molecular simulation results on a well defined fluid model in order to construct a correlation/theory based on this model. If this fluid model is representative of some real fluids then this correlation/theory can be applied to predict properties of real fluids using a corresponding state approach. The Lennard-Jones (LJ) fluid model is a simple two parameters molecular model representing fairly well simple non-associative real fluids at least concerning their viscosity (Galliro et al. 2006). This fluid model respects by definition perfectly a corresponding state behavior. Thus using a large database of molecular dynamics (MD) simulations of the viscosity of the LJ fluid we have constructed a correlation which is able to represent accurately the MD results (Galliro et al. 2005a). MD simulations have been performed in gas liquid and supercritical states.OnePetroTOTALSPE107378Fluid DescriptionFormation WaterModellingStatic and Dynamic Models of Formation Water in Orinoco Belt, VenezuelaJ. Marcos, E. Pardo, J. Casas, D. Delgado, M. Rondon, M. Exposito, and L Zerpa, Sincor, and J. Ichbia and J. Bellorini, TotalAbstract Sincor is a strategic association between PDVSA Total and Statoil committed to the production upgrading and commercialization of extra heavy oil from an area covering over 325 Km2 in the Orinoco Belt (Figure 1). The Sincor area is composed of a series of stacked unconsolidated sand-shale reservoirs with good petrophysical properties. The depositional system can be divided in two main parts Deltaic and Fluvial. Fluvial sands mainly stacked braided channels represent the bottom part of the reservoir. Deltaic sands go from distributary channel and mouth bar to point bar and crevasse splay. Drilling of vertical observation wells and a testing campaign started at the end of 1999. In well tests anomalies in water salinity values were observed: an aquifer salinity of 2300 ppm while some wells produced water at 15000 ppm. At that time high values were considered measurement problems. In 2001 the first horizontal producers started to cut water with similar high values to those observed in some well tests. Since then a multidisciplinary study was launched aiming at defining and characterizing all water sources using well tests (15 vertical wells) and water production data (150 horizontal wells). This information has then been integrated with geological interpretation and reservoir characterization. In this paper a static model is developed using well test information from the area. The model explains why different ranges of water salinities were observed in the oil and water zones. This model was corroborated qualitatively with log information. Dynamic data confirmed and detailed further the initial model. An exponential decrease of water salinity is generally observed with increasing water production or water cut. This phenomenon is explained by probable water influx in the form of fingering from the low salinity aquifer continously displacing high salinity formation water. The exponential curve shape would depend on the tortuosity and length of the path between the water and the produced oil zones. Static and dynamic data are consistent and confirm our model of water production mechanism observed in the field. Introduction SINCOR is a joint venture company between PDVSA (Petroleos de Venezuela SA) Total and Statoil. It aims at the cold production of 200 000 bbl/d of 8.5 API extraheavy oil and at upgrading its quality to 30-32 API in its refinery. The field is located in the south of Anzuategui state Venezuela and the refinery is to the north. The oil is transported via 200 Km of pipeline (Figure 1). The area of Sincor has been divided in cluster areas of 3.2 Km x 1.6 Km. In the middle of each cluster a vertical well is drilled and used as an observation well to obtain geological and petrophysical data. Well tests are occasionally performed and monitoring devices are installed in these wells. Horizontal producers of 1400m are then drilled from the center of each cluster. In eight years more than 400 horizontal wells have been drilled. After one year of production some horizontal wells started to cut water. The rate of increase of their water cut was different depending on the area and the stratigraphic level from which the wells produced. Together with these variable water production behaviors anomalies in some water salinities (higher values) were also observed. Initially these anomalies were interpreted as measurement problems. During more than 3 years the multidisciplinary team created to study these anomalies gradually improved its understanding of the water behavior and eventually reached some interesting conclusions critical for future decisions concerning production policy and reserve evaluations. This paper presents the result of the study.TOTALSPE121902Fluid DescriptionInsitu PVT VariationsMolecular simulationsUnderstanding Compositional Grading in Petroleum Reservoirs thanks to Molecular SimulationsG. Galliero, LFC with CNRS, Pau University; and F. Montel, SPE, TotalAbstract An accurate knowledge of the initial state of a petroleum reservoir is crucial in order to optimize its development plan. Such knowledge relies on a correct description of the spatial distribution of the fluid components. The compositional variations are mainly due to gravitational segregation and thermo-diffusion phenomena. Usually a good estimation of the steady state spatial distribution of the components is obtained by thermodynamic modeling based on an Equation of State (EoS). This heuristic approach is unable to yield any knowledge on the time required to establish a segregated profile and it needs correlation for the thermodiffusion coefficients which is not readily available. One way to provide further information both on the dynamic of the segregation and on the thermodiffusion process is to use Molecular Dynamics (MD) simulations. In this paper Both EoS and MD simulations were applied for the calculation of the fluid distribution in reservoirs. MD results provide insights on time evolution/stability of the fluid distribution and the calculated profile were used to tune the parameters of the EoS model for current applications. On systems for which an analytical solution of the thermo-gravitational problem exists it is shown that the molecular simulations results are consistent with expected profiles. The MD simulations confirmed a non negligible impact of thermodiffusion phenomenae on the concentration profiles. In addition simulations have shown that the transient behavior of both isothermal and non-isothermal segregation follows a diffusion process dynamic based on the mutual diffusion coefficient. Comparison of MD results and EOS based model were made for various systems to evidence the limitation and the relevance of the thermodynamic approach. Gravity segregation calculations are widely used for the reservoir fluid evaluation and for the initialization of the reservoir model. This paper gives an in depth investigation of the underlying physics and direct validation of EoS modeling through molecular simulations. Introduction An accurate knowledge of the initial state of a petroleum reservoir is crucial in order to optimize its development plan. This relies on the ability of describing correctly the spatial distribution of the fluid components. The compositional variations when the fluid column is not subjected to a global convection are mainly due to gravitational segregation (Hier and Whitson 2001; Montel et al. 2007) and to a less extent to thermodiffusion phenomena induced by the geothermal gradient (Ghorayeb et al. 2003; Montel et al. 2007). Usually a good estimation of the convection free steady state spatial distribution of the components is obtained by thermodynamic modeling based on an Equation of State (EoS) (Halldrsson and Stenby 2000). Nevertheless this heuristic approach is unable to yield the time required to establish a segregated profile nor to provide any direct information on the stability of the fluid column. In addition apart from the intrinsic limitation of the EoS such an approach needs an ad hoc correlation to take into account thermodiffusion which is not readily available for all mixtures despite recent improvements for some kind of mixtures (Artola et al. 2008; Kempers 2001; Shukla and Firoozabadi 1998; Wiegand 2004). In many reservoirs the compositional gradients are different from the calculated one assuming stationary state. The deviations are generally explained by the slowness of the diffusion process leading to a partial segregation situation. But the gravitational segregation process is quite different from any usual diffusion processes where the components diffuse through a boundary. All components at any depth are submitted to the gravitational force.TOTALSPE110882Giant FieldIntegrated StudyHandil FieldReviving the Mature Handil Field: From Integrated Reservoir Study to Field ApplicationHenricus Herwin, Emmanuel Cassou, and Hotma Yusuf, Total E&P IndonsieAbstract The Handil field discovered in 1974 is a giant mature oilfield located in the Mahakam Delta Indonesia. The field consists of 555 accumulations and was developed by more than 350 wells with conventional oil recovery methods: natural depletion and peripheral water injection. After many reservoirs have been water-flooded in order to recover the tertiary oil EOR lean gas injection project was started in November 1995 on five reservoirs. The project was successful and extended to the other six reservoirs in 2000. However the field production continued to decline from 200 000 BOPD in the late seventies to 12 500 BOPD in 2003. An integrated study on the largest EOR reservoir was performed to assess the projects performance including 3D geo-modeling reservoir simulation and chemical tracer injection. The study permitted to track the main effects of the gas injection and define reservoir management guidelines for the other lean gas injection reservoirs. In the same time dynamic synthesis has been performed in all accumulation in Handil Field with objective to identify potential by-passed oil and un-drained areas. Following the study an intensive Light Work Over campaign has been launched and three pilot wells each with different completion type have been successfully put on production and became the model for the next Handil development wells; horizontal well equipped by gas lift to recover viscous sandy reservoir in very shallow zone gravel pack equipped by ESP to recover sandy reservoirs in shallow zone and monobore multi-target well equipped by gas lift to recover reservoirs in main zone. The production has been increased by nearly 100 percents from 12 500 BOPD in 2003 to 23 000 BOPD nowadays. Integrated reservoir study and the successful application of Light Work Over and Infill Well to recover by-passed oil and un-drained areas supported by EOR techniques to maintain the reservoir pressure and sweep the tertiary oil become the key elements to revive the mature Handil Field. Introduction The Handil field is located in the Mahakam Delta East Kalimantan Indonesia. The field comprises of 555 unconnected accumulations/reservoirs in structurally stacked and compartmentalized deltaic sands. The reservoirs are trapped by Handil Anticline which is cut by a major impermeable fault dividing the field into two compartments North and South. The reservoirs are found between 200 mSS and 3500 mSS in the surface of 10 km long and 4 km wide.TOTALSPE118892Giant FieldReservoir DevelopmentDeepwaterAKPO: A Giant Deep Offshore DevelopmentF. Rafin, A. Lan, and B. Ludot, TOTAL S.A. FranceSummary All deep water offshore projects are challenging. They are large developments difficult to implement and often beyond the limits of proven technologies at their inception. AKPO field is located in block Offshore Mining License (OML) 130 200 km offshore Nigeria in 1400 m of water. At plateau production AKPO will produce and export 175 000 B/D of condensate and will export at startup 320 MMscf/D of gas to Bonny NLNG plant onshore Nigeria. AKPO reservoirs characteristics have greatly influenced the development scheme while still making it technically and economically viable. AKPO reservoirs consist in a 620-million-recoverable-barrels accumulation of a critical fluid made of very light oils up to 53API and classified as condensate with well head shut-in pressures up to 400 bars fluid temperature up to 116C at wellhead and very high gas liquid ratio (GLR). AKPO is not only a giant condensate field but also a gas field with 1 Tcf planned gas export. With such particular reservoir conditions the AKPO development scheme is very challenging and maximizes the use of proven and generic technologies whenever possible. The development is taking place at a time when the supplier market is very buoyant. This in turn has created additional challenges with respect to the availability of skilled resources and obtaining quality products on time. The paper addresses the challenges of AKPO development and in particular some of the key technical issues. A unique hybrid condensate production/gas export development scheme which maximizes hydrocarbon recovery Reservoir management requiring massive pressure maintenance facilities extensive use of intelligent and selective completions and subsea multiphase flow measurements A development drilling strategy and well architecture. A subsea layout compromise aiming at maximum reliability and availability. Extensive qualification and testing program of equipment to meet with the reservoir conditions. An FPSO concept pushed to the limit to handle high volume of high-pressure (HP) fluids together with a very large gas inventory. The securing of resources in terms of dry dock slot marine spread and deep offshore drilling units in a buoyant market. TOTAL with 24% interest is the operator on OML 130 on behalf of Petrobras of Brazil Sapetro of Nigeria China National Offshore Oil Corporation of China (CNOOC) and Nigerian National Petroleum Corporation (NNPC) of Nigeria. AKPO achieved Project sanction on 25 April 2005 when OML 130 was awarded by the Nigerian authorities. AKPO is currently under development with drilling and construction underway with first production planned before the end of 2008.TOTALSPE109831Heavy OilAssisted HMMore Rapid and Robust Multiple History Matching With Geological and Dynamic Uncertainties: Heavy-Oil Case StudyJ. Poncet, G. Vincent, M. Inizan, P. Henriquel and P. Jannes, TotalAbstract The generation of reservoir simulation models that match field production data has been and is still a long-time industry challenge not only for the time spent on history matching studies but also because of the non-uniqueness of the solution. This paper presents a new approach called Hybrid Models" to accelerate this process and get more realistic history match models. Hundreds of stochastic possible geological models are produced and tested in regard to the dynamic data. The Hybrid model is a composite geological model not only constrained by the initial well data but also with selected parts of the first realizations matching around some wells. This technique allows a relatively quick history matching process and results in a series of matched geological models. This process was applied in part of a heavy oil field (14 horizontal wells in fluvial reservoirs were considered) after 3 years of production. The objective was to explain and reproduce the high water-cut oil rates GOR and bottom-hole pressures in this part of the field. A complete uncertainty workflow was applied with sedimentological and petrophysical uncertainties as well as fluids and dynamic uncertainties. Results showed that static uncertainties were essential to get a coherent match and "Hybrid Model" technology was applied with success. The Hybrid model technique gives several matched geological models. All models have been carried out through forecasting keeping the present development plan evaluating the potential impact of remaining static uncertainties. Dynamic uncertainties were also considered on one geological matched model. Several combinations of dynamic parameters have been computed to keep a match. Corresponding models have been transferred through forecasting. Final conclusions were that at fixed development plan dynamic uncertainties are more to be considered and combined for the forecast than static ones. The use of the "Hybrid models" technique and the integration of static and dynamic properties as matching parameters have been shown to be efficient to produce accurate multiple production history matched models. From those models it has been possible to quantify the remaining uncertainties in terms of future production and to propose new developments. Introduction The field considered in this study produces 8.5API gravity of Extra Heavy Oil (EHO) with a viscosity at reservoir conditions between 1800- 3500cP. The EHO is upgraded to market of high quality 32 API synthetic crude oil. The first phase of development is completed and includes more than 300 horizontal wells. The reservoir section Middle Miocene in age is subdivided in two main intervals. The lower part is mainly stacked unconsolidated sands deposited in a braided - meandering fluvial system. The upper part corresponds to sands encased into a shaly sequence associated to a fluvio-deltaic system with tidal influence. Approximately 80% of producing wells are drilled in fluvial sands characterized by water production risks. In contrast deltaic sands represent 20% of total oil production with little or no water risk. Due to extreme viscosity contrasts after breakthrough the water cut in many wells increases rapidly. In order to get a good understanding of the production mechanism and then propose further development it was clear that the history match phase was essential. This history match was not easy to reach as the main parameter driving the reservoir dynamic behavior was the location of shale barriers within the model. Instead of modifying the geological model on a cell by cell basis (without keeping the geological coherency) a new approach called Hybrid model has been developed in order to get a relatively quick history match preserving the entire geological coherency. Static and Dynamic Uncertainties Before describing this hybrid model technique it is essential to come back to the geological and dynamical models and their associated uncertainties. Those uncertainties will be assessed and ranked with respect to their relative impact on the history matching process before planning the way forward."OnePetroTOTALSPE102094Heavy OilBitumen sandsReserves evaluationQuantifying Resources for the Surmont Lease with 2D Mapping and Multivariate StatisticsWeishan Ren, SPE, ConocoPhillips Canada; Clayton V. Deutsch, SPE, University of Alberta; David Garner, SPE, Chevron Canada Resources; T.J. Wheeler, SPE, ConocoPhillips Canada; Jean-Franois Richy and Emmanuel Mus, SPE, TotalSummary The McMurray formation consists of heterogeneous Cretaceous-bitumen-saturated sands. The reservoirs are thick and laterally extensive in the main fairways. Many commercial projects are in the early stages of development. Resources too deep to mine are considering steam assisted gravity drainage (SAGD) (Butler 1991). Detailed high-resolution 3D geostatistical modeling is useful for individual well-pair or pad flow simulation but is neither practical nor necessary for resource assessment across large areas. A methodology for resource assessment is developed from a geostatistical study on the Surmont lease. The uncertainty in more than 30 correlated variables is calculated on a dense 2D grid using all available information including wells seismic and geologic trends. The correlation structure between the variables is modeled under a multivariate Gaussian model. The local distributions of uncertainty have been checked with cross validation and with more than 100 new wells drilled during the last two drilling seasons. Resource uncertainty across the entire lease area and a number of arbitrary development areas is derived from the 2D maps of uncertainty. A combined P-field/LU simulation approach is used; the global uncertainty is consistent with the local uncertainty. Introduction The McMurray formation contains a large oil-sands resource. A small portion of oil sands can be recovered by surface mining; most of the bitumen resource will be produced by advanced heavy-oil-recovery technology such as the SAGD process. Accurate estimation of the in-situ resource range and associated risks is important for reservoir planning and development. Detailed 3D models of heterogeneity are useful. They provide numerical models consistent with small-scale well data measures of connectivity and visualizations that appear realistic. The challenge of 3D models in the context of our problem is two-fold: the size of the models and the requirement for realistic summaries of reservoir quality at each location. The study area is more than 500 km2 the thickness is on the order of 100m there are more than 10 variables of interest and we would need 100 or more realizations to represent uncertainty. More than 20 billion numbers would need to be routinely manipulated to understand Surmont at a relatively coarse discretization of 50501 m. The second challenge is more subtle. Reservoir management decisions depend on many factors (such as the thickness of good-quality reservoir presence of top- or bottomwater structure of the base reservoir and geological variability). These factors are for the most part areal summaries of the reservoir. They can be reliably calculated from the well data; however they are not as reliably estimated from 3D models. High-resolution geostatistical models do not reproduce all of the complex geological features and trends. This challenge is addressed by research. In summary the advantages of using 2D geostatistical modeling include good estimates of reservoir quality consistent with available well data uncertainty at each location and simple and fast modeling of variables required for decision making. There are several geostatistical techniques that can be used to integrate different data into a geological model including Gaussian-based Bayesian updating (Doyen et al. 1996) collocated cokriging and full cokriging (Deutsch and Journel 1998; Goovaerts 1997). The Bayesian updating approach is used because of its reliability and simplicity in data integration (Deutsch and Zanon 2004). Several reservoir parameters are important. The thickness of net pay or net-continuous-bitumen (NCB) thickness is related to the height of an anticipated steam chamber. The bulk oil weight (BOW) measures the fraction of the bitumen mass to the total rock mass. The porosity net and oil saturation S o over the NCB are related to the recoverable bitumen by the SAGD process. An important feature of many areas of the McMurray is the presence of top water and top gas that can provide a sink for the injected steam and adversely affect recovery. These upper units are referred to as thief zones (TZs) for the injected steam. Each project and company identifies different critical parameters. The typical project will involve predicting 20 to 30 variables at each 2D location. Only a few variables will be described in this review paper. Most of the data are derived from well logs and core data. The available data variables are divided into two types: primary variables that we must predict and secondary variables that are established from the geophysical interpretation or geological trend mapping. Secondary variables are used to constrain the prediction of primary variables away from the well data. The secondary variables are often structural variables. Three structural surfaces will be used in this paper: the bottom surface of the McMurray (BSM) formation the top surface of the McMurray (TSM) formation and the Wabiskaw-McMurray surface (WMS) which is a maximum-flooding surface above the McMurray formation. These structural data are usually quite reliable because of their lateral continuity and they are derived from a variety of data sources (well and seismic data). These three variables and the calculated gross thickness of the McMurray (GTM) are treated as independent secondary variables for the 2D modeling. A schematic workflow is given in Fig. 1 to illustrate each step for local uncertainty assessment and for global resource uncertainty.TOTALSPE103000Heavy OilBitumen sandsReservoir DescriptionFacies Analysis and Architectural Elements Within a Fluvio-Estuarine Sedimentary System: The Lower Cretaceous Bituminous Sandstones of the MacMurray Formation, Alberta (Canada)J. Bailleul, Ecole des Mines de Paris/Total E&P; V. Delhaye-Prat, Total E&P; and O. Parize, Ecole des Mines de ParisAbstract In north-eastern Alberta (Canada) the fluvio-estuarine McMurray Formation constitutes the main bitumen accumulation of the Athabasca Heavy Oil Province. Deposited within the fluvial-to-marine transition zone the McMurray clastic succession is characterized by the lateral and vertical juxtaposition of a wide variety of depositional processes. This led to complex lithofacies variations responsible for uncertainties in predicting reservoir heterogeneities. In this context a realistic paleogeographic reconstitution is necessary to localize sandy reservoirs and optimize the exploitation of bituminous sandstones. The sedimentological study of the McMurray reservoir based on outcrops and subsurface data (cores well logs seismic profiles) has been undertaken along a 150 km north (distal) - south (proximal) transect. Facies analysis permits to constrain depositional environments within the McMurray Formation. We document in detail facies associations corresponding to continental (fluvial/palustral/paleosols facies) estuarine (interaction between tide and fluvial processes) and marine environments (wave-tide to wave dominated processes). A particular attention has been paid to the nature size geometry and bounding surfaces of architectural elements (i.e. fluvial or estuarine channels IHS/point-bars tidal bars incised valley emerged surfaces). Stratigraphic correlations combined with cartographic analysis allow to evaluate how these sedimentary bodies are related in time and space. The McMurray Formation has been previously sub-divided into three units: the fluvial dominated lower McMurray the fluvio-estuarine middle McMurray and the marine dominated upper McMurray. We notably demonstrate on the base of size and amplitude of IHS that the middle McMurray may be sub-divided into stratigraphic sub-units. We also point out the significance of oxidized surfaces overlain by abrupt grain size changes. Such surfaces are important clue for sequential analysis and may have a regional extent. They should be taken into account as a potential accurate correlative tool for the McMurray Formation. Introduction Since few years the oil industry shows a renewed interest driven by technological improvement and high oil prizes concerning heavy oil reservoirs. In north-eastern Alberta (Canada) the lower Cretaceous MacMurray Formation is the main reservoir unit of the Athabasca bitumen oil sand region (Fig.1). The paleogeography of the study area is characterized by a complex network of paleovalleys or major paleochannels that converges toward a main paleotalweg the MacMurray paleovalley. This major fairway displays many reservoirs which is the main target for the oil sand industry in Alberta.However because of important lateral and vertical facies changes and of a lack of well defined reliable regional stratigraphic surfaces optimized exploitation of these heterogeneous reservoirs using SAGD (Steam Assisted Gravity Drainage) and aerial mining technologies remains challenging. In order to be more predictable especially using subsurface data it is essential to characterized sedimentary systems and to evaluate their spatial and temporal distribution. In the Fort MacMurray surroundings (Fig.1) high resolution sedimentological section measurements both on outcrops and cores allow us to propose an overview of lower cretaceous facies encountered within this fluvio-estuarine setting. The analysis of sedimentary facies permits to characterize local depositional environments and associated sedimentary processes. A stratigraphic analysis led to recognize the spatial and temporal distribution of these depositional environments. We propose a stratigraphic framework for the McMurray Formation that aims to facilitate correlations across the area with the scope to better constrain reservoir heterogeneities.TOTALSPE117479Heavy OilDepressuriziationPore Network ModellingDynamic Pore Network Simulator for Modelling Buoyancy-Driven Migration during Depressurisation of Heavy-Oil SystemsC.C. Ezeuko and S.R. McDougall, Heriot-Watt University; I. Bondino, TOTAL E&P UK Ltd; G. Hamon, TOTAL S.AAbstract A number of vertically-oriented heavy oil depletion experiments have been conducted in recent years in an attempt to investigate the impact of gravitational forces on gas evolution during solution gas drive. Although some experimental result indirectly suggest the occurrence of gas migration during these tests (especially at slow depletion rates) a major limitation of such an interpretation is the difficulty in visualising the process in reservoir rock samples. In contrast experimental observations using transparent glass models have proved invaluable in this context and provide a sound physical basis for modelling gravitational gas migration in gas-oil systems. The experimental observations often exhibit somewhat contradictory trends however - some studies showing dispersed gas migration whilst others describe fingered channelised flow - and to date there appears to have been little systematic effort towards modelling the wide range of behaviours seen in or inferred from laboratory tests. To this end we present a new pore network simulator that is capable of modelling the time-dependent migration of growing gas structures. Multiple pore filling events are modelled dynamically with interface tracking allowing the full range of migratory behaviours to be reproduced including braided migration and discontinuous dispersed flow. Simulation results are compared with experiments and are found to be in excellent agreement. Moreover simulation results clearly show that a number of network and fluid para