bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of Inflow Control Valve (ICV) in the Water Injector Well: Case Study on Alpha Field
Authors: Abllah Elias bin , Maulut Muhammad Sanif , Loong Seah Chin 
Published: July 2011

Abstract
Inflow Control Valve (ICV) have been used in the past to enhance performance of producing wells for unfavorable environments, such as non-uniform permeability and pressure variation along the well sections. Nowadays, since Enhanced Oil Recovery (EOR) technique has been advanced, the ICV is introduced to be installed in the injector well, with the aim to produce more oil from the reservoir. The key factor in the success of this project was the use of Petrel to simulate the injection sweep across the entire Alpha reservoir section. Nozzle type ICV is used to obtain a piston-like water injection profile, and thus to achieve the objective of increasing sweep efficiency to recover more oil, and decrease water breakthrough in high permeability zone, if connected to the producers. Firstly, the reservoir is analyzed to choose the best candidate of injection well. Then, the sector modeling is run at the region near the injection well. The sector modeling reduces the time required to run the ICV simulation study. After that, the Base Case is created with open hole injection well. The result of the run is recorded. Then, ICV is installed with the sensitivity studies on the different valve apertures. The results show that the installation of ICV improves the oil recovery by 2%. The optimal depletion strategy for major oil reservoir is pressure maintenance by water injection with ICV. The full field simulation shows that the water production is reduced by 20% for the full field. Therefore, it shows that intelligent completion concepts can be applied at injection well besides at production well. This paper presents an innovative completion technology, fine tuned by reservoir simulations, for balancing the water injection profile into various sand formations zones in an open-hole completed injector well, increasing sweep efficiency.
The In situ Combustion Pilot Project in Bare field, Orinoco Oil Belt, Venezuela
Authors: Perozo H.. , Mendoza A.. , Teixeira J.. , Alvarez A , Márquez J.. , Ortega P , Vasquez P.. 
Published: July 2011

Abstract
The In Situ Combustion Pilot Project (ISCPP) to be carried out in the Orinoco Oil Belt (Venezuela), is a technological project leaded by PDVSA Intevep together with several organizations of PDVSA E&P San Tomé. ISCPP is oriented towards the assessment of such thermal process in the increase of recovery factors in heavy (H) and extra heavy (XH) crude oil reservoirs.
Although the Orinoco Oil Belt was discovered in the 1930s, it was in the 1980s that the first rigorous evaluations were made. Recently, the area was certificated to contain 235 billions of recoverable (20% of recovery factor) barrels of heavy and extra heavy oil.
The ISCPP will allow the study and development of new technologies that increase the current recovery factor in the world’s largest H/XH oil reservoir.
This work covers all of disciplines considered in the project, mainly: The analysis of lab combustion tests using two kinds of cells both prepared with sand and saturated with water and XH crude oil at reservoir conditions.The static and dynamic reservoir simulations using Petrel and Star respectively.The design, construction and completion of producers, observers and air injection wells.The study, analysis and development of surface facilities and the gas treatment system and monitoring, which must have to take care of relevant quantities of contaminant gases such as SO2, H2S and CO.
Based on this study, the technical and economical feasibility analyses were completed. The cold production is expected to begin during first semester of 2011, while the thermal phase involving air injection, which is the aim of the project, will be implemented throughout the second semester 2011.
EOR Evaluation for Baram Delta Operations Fields, Malaysia
Authors: Bakar Mohamad Abu , Chong Yeap Yeow , Nasir Ernieza , Din Azmi , Fui Chai Chon , Adamson Gary , Agarwal Binayak , Valdez Raul 
Published: July 2011

Abstract
The Baram Delta Operations (BDO), located offshore Sarawak Malaysia, consists of 9 fields with an estimated STOIIP of about 4 BSTB. 6 of the major fields in BDO have been on production for more than 30 years. Average recovery factor to date is about 30%. EOR has been planned as an effort to boost the production as well as prolong the life of the field. A preliminary EOR screening study shows that water-alternating-gas (WAG) is the most amenable EOR process for BDO.
A PETRONAS and Shell joint study team was tasked to further extend the screening study conducted in 2005 by developing an EOR Big Picture for BDO. The objective of the study was to quantify the EOR potential in BDO and to develop a holistic areal implementation plan to mature the EOR potential. Scenarios evaluated involved a combination of three gas processes; immiscible hydrocarbon (HC) WAG as well as immiscible and miscible carbon dioxide (CO2) WAG.
All reservoirs in BDO were first screened and ranked. Eligible reservoirs were then characterized into a few groups according to fluid, rock type as well as aquifer and gas cap size. Optimized EOR performance was evaluated using full field models as well as smaller scale, detailed prototype models of a few selected reservoirs. The prototype models were developed using field analogue data which were representative of a particular reservoir group. The performance prediction of the remaining reservoirs not modeled was STOIIP scaling of representative dimensionless curves. The HC WAG reservoirs were all immiscible while the potential CO2 WAG was a combination of miscible and immiscible cases. The subsurface EOR evaluation also included an estimation of infill and water flood potential, associated well count, well cost as well as the net gas import required and the total gas handling required.
This paper presents the details of the systematic approach used to assess the subsurface EOR potential in the BDO fields.
Injectivity and Injection Conformance Study of St Joseph Chemical EOR, Malaysia
Authors: Lo Sho-Wei , Jamaludin Maisarah 
Published: July 2011

Abstract
The St Joseph field, located approximately 135km offshore Sabah Malaysia, was identified as a chemical EOR candidate. The field is undergoing water flood and there are six water injectors. The chemical EOR will utilize the exiting water injectors as well as additional new injectors. The current design of the chemical cocktail is a non-Newtonian fluid that exhibits 3-cp viscosity in the reservoir. The base case injection rate is 10000 bpd into two zones.
In order to achieve the designed injection rate, fractured injection was designed as the base case injection method. Since the viscosity of the chemical cocktail is much higher than that of water, the injectivity and fracture containment were identified as key issues. This paper outlines a simple, yet fit-for-purpose method developed to model the injectivity and injection conformance under the fractured injection conditions using the commercial modeling tool, REVEAL. A box model was constructed with the available geology, reservoir, petrophysical and geomechanical data. Then the box model was calibrated with the dynamic reservoir model to simulate the reservoir pressure behavior during the chemical flood. Finally the fluid rheology data from the laboratory study were applied in the model. Sensitivities of fracture growth to the key input parameters, including stress contrast, injection rate, reservoir properties and injection fluid properties, were examined. The results show that the fracture growth is contained under the base case injection scenario. The fracture containment is sensitive to the injection fluid quality, injection rate and rock mechanic properties. A preliminary operating envelop of the contained injection was defined according to the results. This method is applicable for investigation of the fracture containment for the water and chemical EOR injections for onshore and offshore fields.
Time Lapse Seismic (4D) Application for EOR Immiscible Water Alternating Gas (IWAG) Programme in Dulang Oil Field, Peninsular Malaysia of the Malay Basin
Authors: Ibrahim Ramli , Shahud Noreehan , Ismail Russikin , Kumar Subodh , Isa M Nasrul , Yusop Zainuddin 
Published: July 2011

Abstract
Dulang oil field, an anticline classtic reservoirs with areal extended about 330sq.km in offshore Peninsular Malaysia Basin was discovered in 1981 with water depth of 76m and total STOIIP around 1BSTB (Figure 1). The field was on production since 1991 with cumulative production (as at Jan 2010) around 21% of STOIIP. Immiscible Water-Alternating Gas (IWAG) EOR injection has been identified to be implemented which can enhance the oil recovery further. A Pilot injection project was carried out in sub-block area of the main reservoirs for a period of four (4) years. Full field injection plan has been formulated and has moved-up to execution phase.
Monitoring the flood front movement by IWAG injection becomes a major challenge in this project especially with wide well spacing and high reservoir heterogeneity where "fingering" effect is prone to occur. This paper will describe the application of time-lapse (4D) seismic in the full field IWAG to monitor the flood front movement through times.
A feasibility study was carried out to investigate the detectability and repeatability between two seismic vintages in order to understand the uncertainty. Factors contribute to the chances of success (COS) of the project also being identified. The result shows that through simulation prediction, a cumulative acoustic impedance of 6% to 8% can be observed after two years IWAG injection cycles. Also being described in this paper are the planning of the full field project right from technology identification, screening study, feasibility study and finally the full field implementation.
This information’s are valuable to the industry especially to enhance oil recovery projects where full scope of formulizing the 4D seismic application being evaluated in order to enhance the surveillance and monitoring programme hence ensure the success of the EOR projects.
Evaluating Chemical EOR Potential of St Joseph Field, Offshore Malaysia
Authors: Du Kui-Fu , Agarwal Binayak , Lo Sho-Wei , Ritom Simon , Mekarapiruk Wichaya , Adamson Gary , Chai Chon Fui , Din Azmi Bin , Azizan Norlia , Zakaria Nur Atiqah , Jamaludin Maisarah 
Published: July 2011

AbstractThis paper presents a systematic evaluation of enhanced oil recovery (EOR) potentials for St Joseph Field located in the offshore Malaysia. The field has been in production for 30 years, currently under gas injection and started injecting water in March 2011. Chemical EOR (cEOR) was identified as the most effective EOR process for maximizing ultimate recovery for St Joseph and the two nearby fields. This paper presents the key results of the St Joseph chemical EOR feasibility evaluation. It also discusses an integrated area development concept exploiting the synergies between the three fields of North Sabah, which is recognized as key to a successful cEOR development in the area.This study aimed to understand the size of prize in case of both polymer flood and Alkaline-Surfactant-Polymer (ASP) EOR scenarios using 3D full field models. One dimensional box and single well models were used to understand the physics of the EOR processes whereas the full field model was used to investigate the EOR subsurface development concepts, infill opportunities, injector/producer placements, slug size etc. It is anticipated that the proposed ASP flood will increase the ultimate recovery factor for the EOR targeted sands to circa 65%. Potential subsurface risks/uncertainties were also investigated.The chemical EOR process will involve handling a large volume of chemicals. This represents a major challenge in application of chemical EOR technologies in an offshore environment like St Joseph. Various facilities concepts were examined in detail. The selected concept is a combination of a mobile floating facility for the injection water treatment and chemical injection packages and a platform-based facility for processing the produced fluids/chemical. A pilot injection prior to full implementation has been planned to manage key subsurface/surface uncertainties and main challenges. The detailed studies of the pilot design and implementation are presented in a separate paper.
First Cyclic Steam Stimulation Pilot Test in Sudan: A Case Study in Shallow Heavy Oil Reservoir
Authors: Ruifeng Wang , Xianghong Wu , Xintao Yuan , Li Wang , Xinzheng Zhang , Xiaoling Yi 
Published: July 2011

Abstract
This paper demonstrates the first cyclic steam stimulation (CSS) pilot test in Sudan, which was applied in FNE shallow heavy oil reservoir. B reservoir of FNE field is a shallow, heavy oil reservoir with strong bottom water, burial depth is 520 m. Well tests have shown low oil rates under cold production, averaging at 50–150 BOPD. Denser well spacing will be required if under cold production, which will be quite cost consuming. CSS generally could yield enhanced oil for heavy oil reservoirs. Therefore CSS pilot test has been planned by approaches as follows: 1) investigation of global heavy oil fields with successful CSS histories to confirm applicability in FNE field; 2) Pilot well screening criteria establishment based on sedimentary and reservoir engineering analysis; 3) Perforation optimization to avoid rapid coning based on thermal simulation; 4) steam injection parameters optimization; 5) applicability of natural gas as cost-effective heating source.
CSS Pilot tests on two wells began in 2009. Convincible results have been monitored with well daily rates 3–4 times of cold production wells with low water cut. Another six CSS wells further came on stream from July. 2010, achieving similar positive results. Conclusions drawn from pilot test were as follows: 1) Optimized perforation contributed to low water cut; 2) steam injection density was optimized around 120 t/m; 3) Natural gas as heating source greatly reduce operating cost.
Heavy oil reserves are estimated to take 40% of Sudan’s total reserves. Sudan is also abundant in natural gas reserves, therefore cost-effective CSS development strategy has wide applications for similar Sudanese and African fields. Successful CSS pilot test in this paper highlighted CSS well screening criteria, perforation strategy, steam injection optimization and natural gas utilization, giving a cost-effective staircase for CSS pilot design and implementation.
Applying Real Options Theory in Determining Optimal Policies for a Surfactant Flood
Authors: Alkhatib A. M. , King P. R. 
Published: July 2011

Abstract
Wide scale implementation of surfactant EOR faces many challenges mainly due to the uncertainty in field application (e.g. reservoir heterogeneity, surfactant adsorption, etc). It is important to have the ability to manage this uncertainty to produce optimal implementation policies. This paper suggests the use of Real Options theory as a possible source for a decision making and evaluation method in surfactant flooding. Real Option theory is based on the concepts of the options traded in stock markets applied to real projects. Real Options theory provides a dynamic framework to manage uncertainty and it also provides evaluation methods to produce quantifiable outputs.
The Least Squares Monte Carlo (LSM) algorithm is the evaluation method used in this paper. The algorithm was applied using example cases based on a synthetic reservoir model. The option evaluated was that of finding the optimal time for starting the surfactant flood. It was assumed that the life of the reservoir was 10 years. The option decision nodes were chosen to be at the start of years 4, 5, 6 and 7. The analysis was performed using Schlumberger’s ECLIPSE as the numerical simulator for the surfactant flood and a code was written in MATLAB to run the different simulations and the LSM algorithm.
Three examples were considered, where the first example assumes one state variable, the residual oil saturation to the chemical flood, Sorc. For the second case, surfactant adsorption, Ds, was assumed as the only state variable. The third and final case considered both Sorc and Ds as the state variables. The LSM algorithm demonstrated that, at this basic level, it can produce an optimal policy for a specific option. It was found that most of the optimal surfactant flood starting-times were at year 6. This was mostly due to its proximity to the breakthrough time of the model which was during year 5. The optimal injection policies recommended achieved, on average, an increase in recovery efficiencies of 0.092, 0.069 and 0.070 for examples 1, 2 and 3 respectively in contrast to the no-option scenario of initiating the surfactant flood at the start of the reservoir life (year 0). These values represent the value of the flexibility in initiating surfactant flooding. This method is being considered for more complex and realistic situations.
Interwell Tracer Tests to Optimize Operating Conditions for a Surfactant Field Trial: Design, Evaluation and Implications
Authors: Cheng Hao , Shook G. Michael , Taimur Malik , Dwarakanath Varadarajan , Smith Bruce R. , Muhammad Syafwan , Masduki Agus , Mario Cio Cio , Putra Kaisar Agus 
Published: July 2011

Abstract
EOR by surfactant flooding is the key to unlock next billion barrels of oil for Minas, one of the world’s largest waterflood fields. An Interwell Tracer Test (ITT-1) was performed prior to a Surfactant Field Trial (SFT) to ensure well injectivity, demonstrate pattern confinement, quantitatively describe interwell connectivity and sweep efficiency, and provide sufficient data for reservoir evaluation. The tracer test was designed by numerical simulation. The test started in November 2009 and was terminated in February 2010.
Analytical interpretation based on moment analysis and numerical reservoir simulations were conducted to evaluate ITT-1 results. Interpretation of the test results indicated various operational and reservoir properties that would have likely led to failure of the surfactant pilot. Hydraulic control of the SFT pattern was not achieved; in fact, less than 20% of one tracer was recovered. Many small scale heterogeneities were identified that led to a lower-than-expected reservoir volume contacted. Unexpected communication between the target sand and the underlying sands outside the pattern also contributed to low tracer recovery and low swept volume. The tracer test was history matched, and additional features were incorporated in the reservoir model, and a new tracer design (ITT-2) was optimized to correct low sweep efficiency and poor hydraulic control. New information from ITT-2 will be used to further optimize operating conditions for SFT.
Failure to conduct the tracer tests would have likely revealed these unfavorable reservoir and operational conditions during the surfactant field trail. Had oil recovery been poor (due to low swept volume), it would have erroneously been attributed to a poor surfactant field trial rather than the true causes. ITT-1 is considered successful because it allowed us to redesign injection / hydraulic control during the relatively inexpensive tracer test and thus evaluate the surfactant trial without bias.
A Review of Polymer EOR on Offshore Heavy Oil Field in Bohai Bay, China
Authors: Kang Xiaodong , Zhang Jian , Sun Fujie , Zhang Fengjiu , Feng Guozhi , Yang Junru , Zhang Xiansong , Xiang Wentao 
Published: July 2011

AbstractRecently, CNOOC launched the EOR with chemical flooding on more and more offshore oilfields in Bohai Bay in china. With the useful life of platform and the present production state, polymer flooding is considered as an important technology for the strategic development of offshore heavy oil fields in Bohai bay. Up to 2010, there are 3 polymer EOR projects on heavy oil field which the water cut is between 10 – 80%. And about 20 thousand tons polymer powder was used in 27 wells in the past 5 years. It has been seen that the water cut declined while the oil production increased. The application result shown it is feasible. The history of polymer EOR in Bohai Bay was present in the paper.
Time-Lapse Effects in a Steam Flood Development in South Oman
Authors: Rocco G.. , Adawi R.. , Busaidi K.. , Rodriguez F.. , Busaidi S.. , Kindy F.. , Maamari A.. , Kiyashchenko D.. , Mehta K.. , Lopez J.. , Zwaan M.. , de Zwart B.. 
Published: July 2011

Abstract
A steam flood re-development of a mature field in the South of Oman is well underway with the first pattern of steam injection active since late 2008. The areal surveillance programme designed by a joint effort between Petroleum Development Oman (PDO) and Shell International Exploration and Production (SIEP) includes the simultaneous recording of a variety of seismic methods of different resolution. The main purpose of the time-lapse work is to monitor the steam conformance and sweep efficiency as the steam is injected in this heavy oil reservoir over 1,000 m below surface. Key aspects of the data acquisition campaigns, state-of-the-art processing and time-lapse interpretation will be discussed. The ultimate objective of the programme is to evaluate the effectiveness of the techniques used in order to select the most appropriate and economically viable reservoir surveillance tools for full field deployment.
Miscible GOGD Using CO2 in One of the Iranian Fractured Reservoirs - A Case Study
Authors: Kamali Fatemeh , Khosravi Maryam , Vahidi Akram , Roayaei Emad 
Published: July 2011

AbstractAdvantages of CO2 in enhanced oil recovery for Iranian oil reservoirs offers a unique opportunity to boost incremental oil recovery and reducing emissions of greenhouse gas through geological sequestration. Moreover, because of the dominant role of gravity force in gas injection process in fractured reservoirs, and also relatively low minimum miscibility pressure (MMP) of CO2, therefore, miscible CO2 injection with Gas Oil Gravity Drainage (GOGD) mechanism can be considered as an efficient method in most carbonate reservoirs.In this paper, different production strategies such as vertical and horizontal immiscible and miscible gas injection were applied to find the optimum EOR method in one of the under-saturated Iranian fractured reservoirs.To aim this goal, a study with simulation approach was conducted while the effect of gravity drainage on recovery was investigated besides other mechanisms. A complete analysis of phase behavior, PVT properties of reservoir fluid and CO2 mixture was done. These data were applied in designing of the slim tube and full field simulation model. A fully compositional reservoir simulator was employed to understand the reservoir characteristics, also, verifying the suitability of CO2 injection.Material balance analysis indicated the original oil in place (OOIP) is about 910 million STB with a relatively strong water support. The maximum oil production of 60,000 STB/D was assumed in all simulation cases. Reservoir simulation results revealed that additional oil recovery could be obtained from this fractured reservoir by miscible gas injection, while gravity drainage was the main displacement mechanism. In case of vertical well production, the model predicted an increase in oil recovery about 24 and 28% OOIP for immiscible and miscible CO2 injection respectively. Considering horizontal producers and gravity drainage as the dominant production mechanism, immiscible and miscible gas injection will enhance oil production more than 28 and 36% OOIP respectively.