bluuebunny/crossref_metadata_2025_split huggingface dataset:
Field Experience of Produced Polymer Control in Offshore Oilfield
Authors: Xiang Wentao , Zhou Wei 
Published: July 2011

Abstract
One of the challenges for polymer application in offshore oilfield is the treatment of the produced fluids containing polymer. It would be extremely difficult to deal with when the injected polymer is produced in large volume on the platform. A practical example was illustrated in this paper. JZ west area, one offshore oilfield in Bohai Bay, has been implemented polymer flooding since 2007. In this field, incremental oil and reduced water cut were observed, as the concentration of the produced polymer rised to such a high level that nearly leading to a treatment failure on the platform.
In this paper, reasons of the polymer cross flow are analyzed, and methods to control the cross flow of the polymer solution in the pilot were described. The study shows that separate layer injection and in depth profile control are effective measures to improve the vertical sweep efficiency of the injected agent.
After the measures were applied in the field, the produce polymer concentration has been reduced and the treatment procedure resumed to normal.
It is showed that prevention of cross flow in advance is extremely important for offshore oilfields. This paper gave a practical experience for polymer application in offshore environment.
An Advanced Methodology for Surfactant Based Pilot Design
Authors: Bazin B.. , Douarche F.. , Tabary R.. , Moreau P.. , Morvan M.. 
Published: July 2011

AbstractAfter primary and secondary production of oil from a petroleum reservoir, more than half of the oil is often left in place. In order to improve the process displacement efficiency – so that one can recover some of this remaining capillary-trapped or water-by-passed oil –, it is necessary to screen enhanced oil recovery (EOR) techniques and to apply processes such as surfactant flooding, either Surfactant (S), Surfactant Polymer (SP) or Alkaline Surfactant Polymer (ASP), when recommended.This paper describes an advanced methodology to select EOR surfactant based processes with special emphasis on the design of a formulation by considering real brine compositions. Salinity is the major parameter for the design of an efficient surfactant process. Salinity is defined by running reservoir numerical simulations with SARIPCH, a black oil simulator for chemical tertiary recovery. Inputs are formation water salinity and composition of waterflood brine. Strong heterogeneity of flow properties and resisual oil zones as well as reservoir geometry, for example crossflow, are considered. Results help to define the effective salinity and the salinity window for the surfactant formulation design.Formulation design is performed through a validated High Throughput Screening (HTS) methodology using a robotic platform combined with microfluidic tools. Data on brine compatibility, oil solubilization ratio and water-oil interfacial tension (IFT) are systematically provided. Adsorption measurements are conducted in order to take into account the potential efficiency and the economics of the process. Core flood experiments are performed to validate performances of selected chemical formulation(s). Conclusions are drawn on the key effect of salinity and on the necessity of adopting a methodology giving a first appraisal of the salinity that will be seen by the surfactant slug during its transport.
Application of Miscible CO2 Injection to Maximize Oil Recovery in One of Iranian Undersaturated Oil Reservoirs: Simulation and Optimization Study
Authors: Ghasemzadeh Amir , Momeni Ali , Vatani Ali 
Published: July 2011

Abstract
CO2 injection is one of the most frequently used gas injection EOR methods which its applicability grows very fast because of its abundance, greenhouse effect, easily achievement of miscibility condition and so forth. In this study a compositional simulator has been used to determine the reservoir management and production strategies in order to optimize oil recovery from an Iranian undersaturated reservoir. Due to decline of reservoir production rate, this reservoir is candidate for an enhanced oil recovery (EOR) process. Consequently, three possible scenarios have been used, including: (1) Natural depletion, (2) CO2 injection and (3) Water flooding. A series of numerical compositional slim tube simulations were performed to measure the minimum miscibility pressure (MMP) of separator gas, CO2, N2, methane and enriched gas. The results of slim tube simulation show that among these gases CO2 has the minimum MMP which is about 1000 psi below the current reservoir pressure. Available huge CO2 resource in the vicinity of this field along with high reservoir pressure which is more than the MMP of the CO2 increases the feasibility of miscible CO2 injection in this field.
Full field simulation results show that among the performed scenarios, CO2 injection is the best method to produce this reservoir. This production strategy has resulted in better performance and higher oil recovery and therefore good economics.
Oil Recovery Optimization by Immiscible WAG in Offshore Mature Field: Dulang Case Study
Authors: Rosman Aeishah , Riyadi Slamet , Kifli Azmukiff 
Published: July 2011

Abstract
Dulang oilfield is a multistacked sandstone reservoir offshore Peninsular Malaysia with 19 years of production history. Water injection was implemented to supplement the partial water drive. To date, the field recovery factor is approximately 20%, prompting initiatives to increase the recovery. Based on encouraging results from pilot test and simulation studies, immiscible WAG (IWAG) injection was chosen as the recovery strategy in the recently concluded conceptual field redevelopment study.
Prior to full-field implementation of IWAG injection, optimization studies were conducted to maximize incremental recovery from IWAG injection with optimal cost. The case study presented in this paper is that of the E10–14 sand unit, which is one of the major producing sands in Dulang field. In conceptual development study, the expected ultimate recovery (EUR) is 163 MMstb or 49% of STOIIP, contributed partly by 14 infill wells and IWAG injection, according to results from 3D compositional simulation studies. This is an incremental of 15% or 50 MMstb over the expected recovery from the existing depletion strategy which is expected to yield 35% recovery. The same 3D reservoir model was then used for further optimization by performing modification sensitivity runs on a restoration program of idle wells, infill well locations and numbers and injection rate parameters. Location of infill wells were selected on the basis of mobile oil saturation at the end of simulation run with well restoration and production enhancement. Additional increase in oil recovery was obtained by focusing on mobilizing remaining oil saturation. This was achieved mainly by tuning the injection rate of WAG injectors located at the flank of the reservoir. Through multiple iterations, 52% (173 MMstb) recovery can be achieved from IWAG injection with only 6 infill wells, a marked reduction from the proposed 17 wells in the conceptual development plan. This represents an incremental recovery of 18%.
The performance of edge water injection in Dulang has not been consistent due to operational issues and this has affected the reservoir pressure & oil recovery. However going forward, improved water injection & later optimal WAG injection strategy utilizing existing wells as well as putting in additional drainage and injection points can help increase oil recovery.
History Matching Method for High Concentration Viscoelasticity Polymer Flood Pilot in Daqing Oilfield
Authors: Chen Guo , Han Peihui , Shao Zhenbo , Zhang Xinliang , Ma Moran , Lu Kewei , Wei Changqing 
Published: July 2011

Abstract
Daqing Oilfield has conducted a polymer flood pilot with higher polymer concentration value of 2000mg/L, exploiting its high viscoelasticity to further increase micro-scale oil displacement efficiency. Previous simulation matches for the pilot show that because the simulator being adopted has no capability to simulate the process mechanism of polymer elasticity, the production performance could not be matched when the residual oil saturation value of polymer flood was same with that for water flood.
In order to achieve a good history matching for the pilot, we have modeled polymer elasticity process mechanism based on the laboratory study results as that polymer elasticity process could decrease residual oil saturation value below that for water flood, therefore increase relative permeability of oleic phase, and incorporated the polymer elasticity process model into a in-house simulator, developing a new simulator to have capability to simulate the process mechanism of polymer elasticity. We have also conducted a series of core flooding to measure the residual oil saturation for high concentration polymer flood, obtaining the input parameters for simulation in polymer elasticity process model. During simulation history matching, the relative permeability curve is modified according to the different residual oil saturation value at different polymer elasticity.
By means of these measures, the production performance for the polymer flood pilot has been matched very well, suggesting that: (1) the high concentration polymer flood could not only expand the sweep efficiency, but also increase the micro-scale oil displacement efficiency, (2) the newly developed simulator is suitable to simulate the process of polymer elasticity, (3) we provide a useful simulation history matching method for viscoelasticity polymer flood.
St Joseph Chemical EOR Pilot – A Key De-risking Step Prior to Offshore ASP Full field Implementation
Authors: Chai Chon Fui , Adamson Garold , Lo Sho Wei , Agarwal Binayak , Ritom Simon , Du Kuifu , Mekarapiruk Wichaya , Jamaludin Maisarah , Zakaria Nur Atiqah , Din Azmi , Azizan Norlia 
Published: July 2011

Abstract
Chemical enhanced oil recovery (cEOR) is a complex process which exhibits a number of risks and uncertainties. A successful chemical EOR implementation depends on the success and the ability in addressing all these risks upfront and one of the important de-risking steps is the piloting process before full scale implementation.
St Joseph is an offshore field in North Sabah region of Malaysia chosen for chemical EOR implementation. In line with the implementation of chemical EOR, there are a number of uncertainties and risks associated with such a development. Some key uncertainties are generic to cEOR development, such as the heterogeneity, chemical effectiveness, emulsion, production of sales specification oil, etc. However, there are certain risks and uncertainties that are typical for this particular field, such as fractured injection, offshore environment, large secondary gas cap, etc. In order to de-risk the full field development and get a better handle on the risks and uncertainty, a pilot is planned.
The paper discuses the approach taken for the pilot selection, which includes the qualitative and quantitative assessment of pilot types vis-à-vis key risks, the workflow towards designing the pilot, the modeling approach followed, the facility concept of the design, and injectivity modeling, leading to final pilot design. The paper also touches upon the data acquisition and surveillance plan to analyze the pilot performance and quantitatively address the key risks.
In addition, the risks and uncertainties of the pilot implementation are also discussed, together with the mitigation and remediation methods. The pilot study resulted in the detailed pilot design and data gathering plan. The results of the pilot will be used to determine if chemical EOR is viable for full field development at St Joseph.
Successful Cyclic Steam Stimulation Pilot in Heavy Oilfield of Sudan
Authors: Tewari Raj Deo , Abdalla Fahmi , Lutfi Hisham Galal , Keqiang Yu , Faroug Ali , Bakri Hisham , Guocheng Li 
Published: July 2011

Abstract
This paper illustrates the successful design, implementation and evaluation of cyclic steam stimulation pilot in heavy oil field of Sudan. This field contains heavy oil in multiple reservoirs of Bentiu formations of late cretaceous age occurring at epths of 550–600m. Reservoirs are highly porous (~30%), permeable (1000–2000 mD) and unconsolidated in nature. Fluid properties include viscous crude of degree API 15 – 17 and corresponding viscosities in the range of 3700 cp and 3000 cp at reservoir conditions.
In view of higher viscosities and consequently lower oil rates and envisaged meager primary recovery of around 18–20%, plan is made for thermal enhanced oil recovery (TEOR) application early to overcome the resistance to flow and maximize the recovery. As EOR processes are reservoir and reservoir fluid specific, therefore, it is prudent to understand the reservoir response to the steam injection before full field application. Cyclic steam stimulation has been implemented in eight selected wells spread over the field encompassing varying reservoir characteristics for understanding the efficacy of the process, acquiring the valuable data and operational experience. Equally important objective was to gain experience for minimizing the key risks, associated problems and challenges.
Wells have been completed with heat compatible casing and cement. Steam quality of 75% was injected for 6–12 days and wells were subjected to soaking of 3–5 days. Putting on production an improvement of three to five folds has been realized compared to primary production and first cycle is sustaining more than six months. Actual results are better than predicted in simulation studies with lower steam intensity of 120 m3/m compared to planned 160m3/m. Paper also discusses improvement in oil production and its variation with formation and fluid characteristics, formation thickness, depth of formations, duration of injection and soaking periods along-with response variables like oil-steam ratio and steam/water production. Operational challenges in preventing the heat losses in annulus, lifting challenges and sand production are also discussed.
Gas EOR Methodology and Integrated Basin Forecast of Offshore Sarawak Fields, Baram Delta Malaysia
Authors: Valdez Raul , Jimenez Jaime , Adamson Garold , Agarwal Binayak , Chong Yeap Yeow 
Published: July 2011

Abstract
Gas injection, both Hydrocarbon Water Alternating Gas (HC WAG) and Carbon Dioxide (CO2) WAG, are possible Enhanced Oil Recovery (EOR) technologies to further develop and extend the field life of the Baram Delta Operations (BDO), located offshore Sarawak Malaysia. BDO consists of nine fields with an estimated STOIIP of about 4 BSTB. Over 100 reservoirs are in production within the cluster, with many wells operating as dual completions. The 6 largest fields in BDO have been on production for more than 30 years with an average recovery factor to date around 30%, mainly through natural depletion and aquifer support. Most of the fields contain light, undersaturated oil and after initial screening, gas injection is the most likely technology to extend the life of BDO and boost its recovery. The size, geological complexity of BDO, the number existing and aging offshore platforms and facilities; and then to design and execute a large scale, technically and economically optimal gas injection project, makes producing a fully integrated basin wide forecast challenging.
From a reservoir engineering perspective, simulation of miscible and near miscible gas injection requires compositional characterization and fine model gridding, compared with the size of reservoir, to be able to capture the physics (mass transfer, mixture properties and reduce numerical dispersion) to produce reliable results. Moreover, the economical assessment needs to have reliable estimates of incremental recovery, gas breakthrough times, gas utilization and gas recycling. Hence, small scale sector models rather than full field simulations are preferred so more robust results can be generated. The small scale model predictions, essentially building blocks, can then be scaled-up to generate full field forecasts.
Likewise, the implementation of a gas injection project requires an appropriate balance between enhancing oil recovery and facility constraints. The size and cost of facilities, the cost of gas supply, and the acceleration in oil production control the economic viability, and a good design comes from a balance between these variables. Consequently, there is the need to create multiple scenarios of how the gas injection will be managed not only for each reservoir and/or each field, but also the integration and timing of injection of neighboring fields. Rapid forecasting of dozens of reservoirs and 6 fields is required to adequately assess optimal staging and economical viability before selecting a final concept.
This paper presents the methodology used to build robust full field forecasts capturing key physics for the Baram Delta gas injection study. In addition to the methodology employed, a brief description will be given of the models developed and used as input into the full field forecasts, a brief description of the scale-up tool used, examples of forecasts developed will be shown and a summary of strengths and future enhancements.
A Chemical Agent Enhancing Recovery of the Heavy Oil Reservoir
Authors: Zhang Fusheng , Ouyang Jian , Feng Xinfang , Xu Liqing , Lin Hong 
Published: July 2011

Abstract
On the basis of analysis of the main reasons for poor oil recovery of heavy oil reservoir by water flooding and according to the mechanism of the enhancing oil recovery, a chemical agent, which is composed of nonionic surfactants, anionic surfactants and emulsion stabilizers, can adapt to heavy oil reservoir with high temperature and high salinity. The core displacement experiments show that displacement system containing chemical agent can enhance oil recovery by over 20% comparing to water flooding, and the chemical agent contained in produced fluid has no negative effect on demulsification. Mechanism by which chemical agent enhance oil recovery of heavy oil reservoir are: (1) significantly decreasing viscosity of heavy oil to improve mobility ratio volumetric and improve sweep efficiency; (2) decreasing oil-water interfacial tension to increase capillary number and improve oil displacement efficiency; (3) changing wettability of the rock surface from oil-wet to water-wet to change capillary force from the resistance force to the motive force, and drive the residual oil out of the small pores and the wall of pores and increase oil displacement efficiency.
Mechanistic Modeling of CO2-Foam Processes in Fractured Chalk Rock: Effect of Foam Strength and Gravity Forces on Oil Recovery
Authors: Zuta John , Fjelde Ingebret 
Published: July 2011

Abstract
Recent laboratory and mechanistic modeling studies have demonstrated that CO2-foam has the potential to recover additional oil in fractured water flooded chalk rock with low matrix permeability. The CO2-foam processes were carried out in short core plugs by injecting pre-formed foam at 340 bar and 55°C. The fractured model was represented by core plug with a 0.3 cm diameter hole drilled though the centre, and packed with monodispersed glass beads. Calculated mobilities also indicated that CO2-foam is highly effective in decreasing the mobility of CO2 and increasing the apparent viscosity of CO2 in fractured chalk rock.
In this work, mechanistic simulation studies based on history-matched foam models tuned to laboratory data are used to investigate the effect of the strength of pre-formed foam and the role of gravity forces on oil recovery in long fractured chalk models. Pre-formed foam was injected either horizontally or vertically (from the bottom) at 340 bar and 55°C. Pure CO2 injection was also injected in fractured chalk models and used as base cases. The foam qualities and water saturation were varied.
Results indicate that decreasing the foam quality increases the rate of oil production with both horizontal and vertical injection of pre-formed foam. However, the oil recovery efficiency with horizontal injection of pre-foamed foam was higher than with vertical injection. The simulation results show that molecular diffusion is an important oil recovery mechanism in chalk fractured rock with low matrix permeability and should be taken into account, and that considerable gravity effect can affect the oil recovery in horizontal injection of pre-formed foam. The mechanistic models can be used to study CO2-foam processes in fractured chalk reservoirs with multiple fractures.
Optimizing Polymerflood via Rate Control
Authors: Sharma Mohan , Taware Satyajit , Datta-Gupta Akhil 
Published: July 2011

AbstractThe use of injection and production rate control is a common practice for optimal waterflood management. However, the benefits of rate control for enhanced oil recovery (EOR) processes have not been fully explored. In this paper, we examine the role of rate optimization in polymerflooding to maximize sweep efficiency and to minimize polymer recycling by delaying polymer breakthrough.Field scale rate optimization problems for EOR processes involve complex physical and simulation models, production and facility constraints, and a large number of unknowns. Deployment of smart well completions with inflow control valves (ICV) to control production/injection rates for various segments along the wellbore further compounds to the complexity of the optimization. We propose a practical and efficient approach for computing optimal production/ injection rates for polymerflooding with application to smart wells. Our approach relies on equalizing arrival time of the floodfront at all producers to maximize the sweep efficiency and additional ‘norm’ constraints on the arrival times to achieve production acceleration. The ‘optimal’ rate strategy is decided based upon a compromise between maximizing sweep efficiency and production acceleration. We use streamlines to compute the analytical sensitivity of arrival times with respect to well rates. Analytical forms for gradient and Hessian of the objective function are derived, making our optimization computationally efficient for large-scale applications under a hierarchy of operational and facility constraints.We demonstrate our approach using a 2D synthetic example and a field-scale application. The results clearly demonstrate the benefits of rate optimization either by reducing polymer usage or increasing oil recovery. In particular, the 3D field-scale application results in achieving higher oil recovery and reducing associated water and polymer production for the same amount of polymer injection. The geological uncertainty has been accounted for via a stochastic optimization framework based on a combination of the expected value and variance of a performance measure from multiple realizations.