bluuebunny/crossref_metadata_2025 huggingface dataset:
A Case Study in Cased-hole Log-inject-log Techniques to Determine Residual Oil Saturation to ASP Injection
Authors: Schulz R. A.
Published: July 2011

The onshore Seria field in Brunei Darussalam has been producing oil for over 80 years and is approaching the end of primary production. Estimated remaining oil-in-place volumes are significant enough to consider enhanced oil recovery techniques. Alkaline-Surfactant-Polymer (ASP) flood is under investigation as a potential method to increase the recovery in the field. Sand pack and core flood experiments indicate that remaining oil saturations may be reduced sufficiently to warrant commercial application of ASP flood technology in the Seria field. To assess feasibility of this process under reservoir conditions, a single-well, multi-zone injection test using Log-Inject-Log (LIL) techniques was executed. The objectives of this test were to determine injectivity of ASP fluids and to estimate changes in residual oil saturation (Sor) in the near-wellbore region. This paper discusses the preparation, execution, and learnings associated with the LIL activities employed to assess chemical effectiveness of the ASP slug.

Standard open-hole logs were acquired in a newly drilled well to confirm static reservoir properties and to determine the current oil saturation. The original LIL logging program included Schlumberger’s Reservoir Saturation Tool (RST) in pulsed neutron spectroscopy mode (also known as carbon/oxygen or C/O logging) as the primary evaluation method to quantify changes induced by ASP flooding. This was initially supplemented by the slim Cased-Hole Formation Resistivity (CHFR) tool and further supplemented by RST sigma logging and additional cement bond logging to identify sweep outside of perforated intervals. The use of multiple logging tools and the integration of logging results provided corroborative evidence for reduction in oil saturation outside of perforated intervals resulting from acid/brine, polymer/brine and ASP/brine injection as well as valuable insight into changes in the near-wellbore region that would otherwise be missed using a single logging method.
Experimental PVT Data Needed to Develop EOS Model for EOR Projects
Authors: Shaikh Jawad Azeem , Sah Pashupati
Published: July 2011

Compositional reservoir simulations for fields undergoing gas injection are dependent on an Equation-Of-State (EOS) model that will correctly simulate the reservoir fluid phase behavior independent of concentration of injection gas. Such an EOS model will require extensive Enhanced Oil Recovery (EOR) PVT Experiments. It is important at the start of an EOR PVT project to define what experiments need to be undertaken. Only then will it be possible to define the sample volume needed to carry out all the EOR PVT experiments. The reservoir type will determine whether the samples can be taken from bottom hole or from the separator. Fluid samples at atmospheric conditions also need to be taken to carry out Carbon Number (True Boiling Point) distillation test. Different samples will generally have to be comingled to avoid compositional variations between samples used for different experiments.

Gas injection is most efficient if the reservoir pressure is higher than the minimum miscibility pressure (MMP). Miscibility develops through a critical point and therefore in addition to routine PVT data it is also important to measure EOR PVT data that will provide information about MMP and near critical phase behavior. The MMP is measured in a Slim Tube test while a Solubility Swelling Experiment will give the Px-diagram including the critical conditions and composition. It is also recommended to perform the Equilibrium Contact Mix and Multi Contact Studies to measure properties inside the phase envelope at near critical conditions. These two experiments need to be carefully designed to ensure to get the most out of them in the EOS modeling work.

The paper will outline design of EOR experiments, details to be aware of when carrying out the experiments and key data to be matched by the final EOS model.
Feasibility for the Application of In Situ Combustion in Faja Petrolifera del Orinoco (FPO) Based in a Novel Screening Criteria for the Technology
Authors: Hincapie Rafael , Tovar Francisco , Alvarez Carlos
Published: July 2011

Faja Petrolifera del Orinoco (F.P.O) is by far the largest known heavy and extra heavy oil accumulation worldwide, located at north of Orinoco river in Venezuela contains about 1300 MMMBN of OOIP and 297 MMMBN of recoverable reserves. Exploitation of FPO has been done until present mainly by cold production, reaching recovery factors, is best cases, of about 10% of OOIP. PDVSA in recent years has conducted studies of quantification and certification of reserves, based on recovery factors that consider EOR projects. In situ combustion, the older member of thermal oil recovery family, is a method with a high thermodynamic efficiency that has allowed reaching recovery factors over 50% in some fields, accomplishing technical and economical success. This work presents a state of the art of combustion process and a review of the reservoir characteristics and field performance of successful applications in Venezuela and the rest of the world. These data were used to establish an application window, without weighting the size or significance of the reservoirs. This window, combined with data from reservoir characterization for the first six blocks of the FPO Junín area, was used to visualize the most prospective areas for the application of the process using parameters of thickness and water saturation in a commercial reservoir characterization software, followed by a qualitative evaluation of pressure, viscosity, temperature and depth, calculating this way the volume of oil and associated areal space occupied. Results obtained define Junín Blocks 5 and 6, specifically in areas of Basal Sands and Oligocene as the ones with the most potential, therefore, detailed studies should be performed to assess the technical and economical feasibility of the process implementation in these areas.
Experimental and Numerical Simulation Study on Single Layer Injectivity for CO2 Flooding in Low Permeability Oil Reservoir
Authors: Hongwei Yu , Xinmin Song , Siyu Yang , Dingfeng Chen
Published: July 2011

Supercritical carbon dioxide can keep miscible with crude oil, and eliminating the two-face interface existed in conventional water and gas flooding. The displacement efficiency in laboratory experiment is nearly 100%, so it has the potential to increase oil recovery significantly. However, in practical application of CO2 miscible flooding, severe disaccord appears with injection time increasing between the single layer’s injectivity and its physical property because of many influencing factors, the injection ratio of high permeable layers increases, and the injection ratio of low permeable layers decreases, the injectivity of single layers is unbalanced seriously, so the CO2 swept volume will be influenced, finally leading to the poor EOR result. According to the laboratory experiment of parallel connection cores, injection and production profile in practice and the prediction of numerical reservoir simulation, getting the conclusion that the main influencing factors for the injectivity of single layer are interlayer heterogeneity, mobility ratio, gravity, CO2 molecular diffusion and capillary force, and interlayer heterogeneity influences injectivity most seriously. For avoiding the injectivity disaccord, based on these influenced factors, suggestions have been offered to the CO2 miscible flooding pilot test in Jilin oilfield, these suggestions can provide reliable methods for enlarge CO2 flooding swept volume.
Evaluation of Alkali-Surfactant Effectiveness by Single Well Test Pilot in a Malaysian Offshore Field Environment
Authors: Manap Arif Azhan , Chong Mizan Omar , Sai Rithauddin M. , Zainal Suzalina , Yahaya A. Wafi , Othman Mohamad
Published: July 2011

Angsi field is located offshore Terengganu, Malaysia. It was identified as the candidate for a pilot project to evaluate the effectiveness of chemical enhanced oil recovery (CEOR). Injection of alkali-surfactant (AS) slug was used to improve recovery factor through the reduction of residual oil saturation (Sor). The pilot project utilized single well chemical tracer test technique (SWCTT) to measure Sor change near well bore due to reactions of CEOR process. The pilot results were later used to update the reservoir dynamic model and to support decision making for potential expanded field application.

The pilot project faced many challenging technical and operational obstacles: offshore location, high reservoir temperature, sea water as injection water, water softening facilities requirement, and unmanned satellite platform with limited space. In addition, compliance to all Health, Safety, and Environment (HSE) requirements is a must, to ensure the pilot operation is carried out in a safe manner.

This paper will focus on the overall pilot design, planning and some results. Operational, HSE and quality control will also be discussed as background to the pilot project.
EEOR Success in Mann Field, Myanmar
Authors: Ott William K. , Nyo Thu , Nyunt Aung Win , Thet Khaing Aung
Published: July 2011

Oil production increased in two test wells in a mature oil reservoir in Mann Field, Myanmar by successfully applying an enzyme-enhanced oil recovery (EEOR) process, a subset of microbial-enhanced oil recovery. A concentrated, water-soluble enzyme preparation made from DNA-modified proteins released from selected microbes was specifically prepared and injected in oil zones of one well and then recycled and applied in a second well.

Mann Field is a brownfield located in Salin sub-basin of the central basin of Myanmar in Southeast Asia and currently is operated by MOGE, with MPRL E&P Pte Ltd as the contractor for the field operations management. The field began producing in 1970, predominately from Oligocene reservoirs that consist of 26 stacked sandstone payzones. More than 667 wells have been drilled and completed, and 118 million stock tank barrels of oil have been produced. Average porosity of the field is 18% with an average permeability of 10–250 md. Oil gravity is typically 36.5°API, which is paraffinic in certain horizons, and the gas gravity is 0.65.

A test well was treated with four drums of enzyme concentrate diluted to 2% in formation compatible, filtered brine. Pretreatment production was 14 bopd and 2 bwpd. Current production is 18 bopd, and some 530 incremental barrels have been produced in 13 months following the 11,000 galtreatment. Pretreatment production from the second well was 10 bopd and 109 bwpd. Current production is 16 to 17 bopd, and approximately 1636 barrels of incremental oil has been produced during nine months since the treatment. Additional enzyme treatments are being designed for wells in Mann Field with higher current oil productivities.

There are unlimited targets for EEOR applications, not only in Myanmar, but throughout the world. These successful initial EEOR applications in Mann Field will allow for treatment design improvements in future wells.
Thermally Active Polymer to Improve Sweep Efficiency of Water Floods: Simulation and Pilot Design Approaches
Authors: Garmeh R.. , Izadi M.. , Salehi M.. , Romero J. L. , Thomas C. P. , Manrique E. J.
Published: July 2011

A common problem in many waterflooded oil reservoirs is early water breakthrough with high water cut through highly conductive thief zones. Thermally active polymer, which is an expandable sub-micron particulate of low viscosity, has been successfully used as an in-depth conformance to improve sweep efficiency of waterfloods.

This paper describes the workflow to evaluate technical feasibility of this conformance technology for proper pilot project designs supported with detailed simulation studies. Two simulation approaches have been developed to model properties of this polymer and its interaction with reservoir rock. Both methods include temperature triggered viscosification and adsorption/retention effects. Temperature profile in the reservoir is modeled by energy balance to accurately place this polymer at the optimum location in the thief zone. The first method considers a single chemical component in the water phase. The second method is based on chemical reactions of multiple chemical components. Both simulation approaches are compared and discussed.

Results show that temperature-triggered polymers can increase oil recovery by viscosification and chemical adsorption/retention, which reduces thief zone permeability diverting flow into unswept zones. Sensitivity analyses suggest that ultimate oil recovery and conformance control depends on the thief zone temperature, vertical to horizontal permeability ratio (Kv/Kh), thief zone vertical location, injection concentration and slug size, oil viscosity, chemical adsorption, and its reversibility, among others. For high flow capacity thief zones and mobility ratios higher than 10, oil recoveries can be improved by increasing chemical concentration or slug size of treatments, or both. Low Kv/Kh (< 0.1) and high permeability contrast generally shows faster incremental recoveries than high Kv/Kh with strong water segregation reservoirs.

The presented workflow is currently used to perform in-depth conformance treatment designs in on-shore and off-shore fields and can be used as a reference tool to evaluate benefits of the thermally active polymer in waterflooded oil reservoirs.
Application of Polymer Flooding with High Molecular Weight and Concentration in Heterogeneous Reservoirs
Authors: Xiaoqin Zhang
Published: July 2011

Daqing oilfield is a heterogeneous sandrock oilfield with multilayers. The application of polymer flooding in the field has obtained significantly technological and economic effects. On the bases of numerous lab experiments, it is indicated that polymer solutions of high concentration and molecular weight have better absorption and captation toward the layers than normal solutions do. Besides, the resistance and residual resistance coefficients are much larger. The higher the concentration and molecular weight are, the larger the increment in viscoelasticity is. Once polymer flooding with high concentration and molecular weight is applied, the residual oil saturation will decrease and displacing efficiency will increase. All these lead to higher increment in recovery rate.

Three pilot tests were conducted by means of high concentration and molecular weight. On the bases of the obtained results, industrialized application of the recovery method first began in the N1 block of Sazhong Area in Daqing oilfield in Jan. 2009. In that block, the molecular weight of the polymer solution was 25million Dalton and the concentration was 2000mg/L. Maximum decrement in water cut was 30 percent and enhanced recovery rate was 8.3 %. It was estimated that enhanced recovery rate could ultimately reach 18 percent by the end. The successful application of polymer flooding with high concentration and molecular weight in Daqing oilfield would provide practical experience for the development of similar reservoirs.
Biology Enzyme EOR for Low Permeability Reservoirs
Authors: He Liu , Zhonghong Zhang
Published: July 2011

Biology enzyme may change wettablity of rocks, release surface hydrocarbon of formation rock particles, and reduce interfacial tension. These properties may be used to reduce water injection pressure of low-permeability oil reservoirs, to enlarge swept volume and enhance recovery rate. We applied 4 types of biology enzyme solutions with different concentrations ranging from 0.5% to 5.0%, to conduct depressurization experiments on 6 artificial cores and 3 natural cores. When concentration of biology enzyme was 2.0%, injection pressure dropped significantly by 22.6% to 72.7%, averagely a drop of 51.4%. Pilot tests have been carried out based on indoor experiment results, as well as economic factors and operating convenience considerations, and other oilfield experiment parameters references. When volume multiple of injected biology enzyme was chosen to be 0.6%PV, production declination of connected oil wells was controlled and production rose gradually, showing that formation pressure has been restored and biology enzyme has played a part in enhancing the oil recovery rate.
Large Scale High Viscous-Elastic Fluid Flooding in the Field Achieves High Recoveries
Authors: Demin Wang , Gang Wang , Huifen Xia
Published: July 2011

By conventional mechanism, polymer flooding, due to its high viscosity, decreases the mobility ratio, increases the Volumetric Sweep Efficiency and recovery of the reservoir. When the fluid viscosity reaches a certain value, the decrease in mobility ratio has less effect on further increasing the volumetric sweep efficiency, therefore the practical amount and concentration of polymer that is used is limited.

However, due to the mechanism that the elastic properties of the driving fluid can increase the Displacement Efficiency, Daqing Oil Field started pilot tests of high elasticity driving fluid in the field 9 years ago, the incremental recoveries were all more than 20%OOIP above that of water flooding, about double that of conventional viscosity (40~50 cp) polymer flooding. Due to the very good results, in the recent 3 years, Daqing has rapidly expanded high viscous-elastic fluid flooding to more than 5 thousand wells. From the results of 1000 wells that are using this EOR method and for a sufficient time to predict the results, all these large scale field floods will attain an incremental recovery of more than 20%OOIP. Therefore, in Daqing, high elasticity flooding is taking the place of conventional polymer flooding and alkaline-surfactant-polymer (ASP) flooding to increase the oil field recovery.

Field experience shows the difficulties in solving the technical problems of producing, pumping, gathering and treating produced fluid from high viscous-elastic flooding are about the same as that of conventional polymer flooding and much easier to solve then ASP flooding.

The field results also show that the economics (costs per ton of produce oil) of this EOR method is about the same as conventional polymer flooding.

This is a very promising new EOR method that could significantly increase the recovery in other fields.
The Research on Optimizing the Plan of New Unary Polymer Surfactant Improving the Effect of Development in Thick Oil Pay
Authors: Ma Kuiqian , Cai Hui , Hou Yawei , Lei Yuan , Wang Chuanjun , Zhang Hongyou , Wu Xiaozhang , Zhang Zhanhua , Huang Qin
Published: July 2011

Polymer surfactant is a unitary flooding system which be developed in recent years. It has dual characteristics of polymer and surfactant. It has strong solvency even at a lower concentration. It has low molecular weight, counter-mass, high viscosity, anti-shearing force, anti-biodegradation, anti-oxidation degradation, temperature-resistance and salt resistance, and it fits different permeability reservoir. It is also be used to under different mineral degree condition reservoir and be injected with waste water directly. For the situation which not only has the serious invalid injection and production, but also has the oil layer of remaining oil enrichment, the test area carried out comprehensive research on polymer surfactants’ profile modification to improve the development effect of thick oil pay.

In this paper, the viscosity increasing property, stability, viscoelatic property, absorption characteristic, interfacial tension, flow characteristic and molecular coil size of the polymer surfactants is studied through laboratory test. The mathematical model of active constituent qualitative change of polymer surfactants flooding is established. The oil displacement scheme of polymer surfactants flooding in test area is optimized. The latest site implementation shows that polymer surfactants has a good suitability for tap potential in thick oil layer, the cumulative oil has increased 5978.5t, and predicting the enhanced oil rate is 1.7 points.
Challenges in Processing Produced Emulsion from Chemical Enhanced Oil Recovery - Polymer Flood Using Polyacrylamide
Authors: Zheng Frank , Quiroga Pilar , Sams Gary W.
Published: July 2011

Polymer flood using polyacrylamide is an effective way to increase oil production in many aged fields. While extensive research and development and field practices have demonstrated the improvements in oil recovery using this technology, the development on effective methods of processing the produced emulsion from polymer flood lags behind. The polymer in the injection fluid, which alters its physical and chemical behaviors, ultimately breaks out with the produced emulsion and changes its physical and chemical characteristics. This leads to tighter emulsions, increased produced water viscosities, stronger chemical interactions, limitations on the processing methods and process conditions, reduced efficiency on current equipment technologies, and even excessive equipment failures and damages. Adding to the processing difficulties is the uncertainty of the break out fluids. As polymer passes through reservoirs, its physical and chemical properties change due to formation absorption, shearing, and chemical reactions. As a result, the produced polymer is different from the injected polymer, and constantly changing during the production cycle. This requires the emulsion processing technologies to be flexible and stable throughout a large operation envelop.
The Comparative Advantages of a Dedicated CEOR Vessel for Offshore Field Developments
Authors: Wodehouse J.. , Henthorne L..
Published: July 2011

Description.

Low salinity water floods and chemical enhanced oil recovery (CEOR) injection (Alkali, Surfactant and Polymer) are two technologies which have been applied onshore but are now being studied for use in new and existing offshore field developments. Their application offshore introduces several issues, which can significantly affect the technical feasibility and commercial viability of the project:

Applications.

The results presented in this paper are generic but they provide a basis for further study of the application of a dedicated desalination / CEOR vessel using specific field information. A work sheet has been provided in the paper identifying the most likely design concept(s) of a dedicated CEOR unit for a range of different field location parameters.

Results, Observations, and Conclusions.

In many cases the lowest risk and most cost efficient design is to locate the desalination / CEOR facilities on a separate vessel. This paper addresses the comparison of these issues in a qualitative manner for different design scenarios. The concept selection comparison is based upon engineering studies and typical offshore industry cost metrics.

Technical Contributions.

This paper presents a basis for considering a dedicated CEOR vessel for offshore projects. This is a novel concept and by initiating further detailed analysis for specific field developments this paper could provide the impetus for the recovery of a significant amount of additional offshore field reserves.
Improving Chemical EOR Economics by Optimizing Water Quality
Authors: Henthorne Lisa , Hartman Meghan , Hayden Andrea
Published: July 2011

Chemical enhanced oil recovery (CEOR) is emerging as a vital method to increase recoverable oil from aging reservoirs, but economics and the achievable incremental recoverable oil will dictate its widespread adoption. Water chemistry of the injectant plays an important role in the effectiveness and cost of CEOR. For instance, in polymer floods using partially hydrolyzed polyacrylamides (PHPAM), it is well established that the realizable viscosity for a given polymer concentration is a function of the injection water salinity, with divalent cations having a more detrimental impact than monovalent ions. Studies have shown that five to ten times less PHPAM is required using desalinated or lower salinity water when compared to seawater, resulting in an equivalent cost savings related to polymer consumption. In surfactant flooding, the relationship between the injectant water chemistry and the effectiveness of the flood is a more complex equation. Considerable research is ongoing to predict optimal salinities for surfactant flooding and the added benefit of using salinity gradients through the life of the surfactant flood. And lastly, alkalinity addition to either a surfactant and/or polymer flood dictates the injectant water be softened to prevent calcium and magnesium carbonate precipitation if sodium carbonate is the source of cost-effective alkalinity. Further complicating matters, the injection water salinity must be kept at a level sufficient to prevent clay swelling in the reservoir, and sulfate levels must be low enough to prevent precipitation of the sparingly soluble salts of barium or strontium, if present.

This paper analyses the economics associated with an alkalinity-surfactant-polymer (ASP) flood using general characteristics of an ASP flood project and demonstrates how optimizing the water quality of the injection water can change the project economics. Creating customized water chemistries of optimal blends throughout the CEOR flood is possible by carefully choosing membrane and polishing technologies which allow for a range of possible chemistries. Reducing the cost of CEOR through optimized water chemistries may further enhance oil recovery on a global scale by expanding the number of reservoirs in which CEOR is economically attractive.
Uncertainty in MMP Prediction from EOS Fluid Characterization
Authors: Dzulkarnain I.. , Awang M. B. , Mohamad A..
Published: July 2011

Published results on modelling crude oils by equation of states (EOS) showed the importance of tuning the equation to fit experimental data closely. Usually various parameters relating to C7+ such critical properties are altered to obtain an equation with a high regression correlation. Although current oil samples may be analysed up to C60+, the presence of isomers for each component may still cause a high degree of uncertainty in the averaged properties. The use of different tuning factors can also cause variations in the equation of states. In practice, the fluid model after tuning does not always give good prediction for all properties. For example, a good fit for saturation pressure and viscosity may give considerable difference in the density prediction. Another set of tuning may be excellent for another property and poor fit for another. Since the prediction of the minimum miscibility pressure (MMP) depends on the EOS model, variations in the model will result in differences in the MMP value. Therefore the priority set on each property during tuning may result in widely differing MMP values.

This research aims to find a relationship on the effects of each property of a crude oil on the MMP predicted. Peng-Robinson (PR) and Soave-Redlich-Kwong (SRK), five properties and key tuning parameters are varied. The impact of using different combinations of the critical properties correlations on MMP calculation are tested on gas/oil systems.

The best fit that is chosen from a tuning process may not always give a good fit to all properties. Our results may be used to list the priority of each property during tuning and will allow an estimation of the uncertainties in each property.
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

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

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

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

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

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

This 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

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

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

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

Recently, 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.