bluuebunny/crossref_metadata_2025 huggingface dataset:
Oil Recovery Optimization by Immiscible WAG in Offshore Mature Field: Dulang Case Study
Authors: Rosman Aeishah , Riyadi Slamet , Kifli Azmukiff
Published: July 2011

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

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

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

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

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

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

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

The 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.
Simultaneous Injection of Water and Polymer (SIWAP) to Improve Oil Recovery and Sweep Efficiency from Layered Carbonate Reservoirs
Authors: Masalmeh Shehadeh K. , Blom C. P. , Vermolen E. C. , Bychkov A.. , Wassing B..
Published: July 2011

A new EOR scheme is proposed to improve sweep efficiency and oil recovery from heterogeneous mixed to oil-wet carbonate reservoirs. The reservoir under study is a highly heterogeneous and layered reservoir which can be described at a high level as consisting of two main bodies, i.e., an Upper zone and a Lower zone with a permeability contrast of up to a factor of 100.

The main recovery mechanism currently applied is water flooding. Field data shows that injected water tends to travel quickly through the Upper zone along the high permeability layers and bypasses the low permeable Lower zone, which results in poor sweep of the Lower zone. It has been demonstrated in earlier publications that this water override phenomenon is caused by capillary forces which act as a vertical barrier and counteract gravity for mixed or oil-wet reservoirs.

Polymer flooding has been proposed to improve sweep efficiency in heterogeneous reservoirs. In this paper we propose a new polymer based EOR option in which the water and polymer are injected simultaneously into the Lower and Upper zones, respectively. Injection of polymer into Upper zone serves to minimize cross-flow of injected water from the Lower zone and improves the sweep efficiency of both Upper and Lower zones. Compared to polymer injection alone, a much lower volume of polymer is required which has a significant positive impact on cost of this EOR process.

Numerical simulations have been performed using a history matched sector model. The model forecasts show that significant sweep improvement of the Lower zone is achieved compared to conventional water or gas injection. The results also show that the process is stable and robust to reservoir lateral and vertical heterogeneity, variation in polymer viscosity and that the amount of polymer that is used can be limited by only injecting a polymer slug of 0.1 to 0.2 pore volume. It is also shown that the process can be implemented in secondary and tertiary mode, where in tertiary mode earlier handling of production water is required. Experimental work shows there are promising polymers that may be able to withstand the high reservoir temperature, high salinity and high concentration of divalent ions in the reservoir under study.
Selection of Investment Portfolios and Funding Options with Joint Ventures in Oil and Gas
Authors: Ndiaye M. M.
Published: July 2011

In Oil and Gas Industry, due to the high investment in projects, the long payback period and the high risk involved, selecting the best projects portfolio and ways to minimize risks are difficult challenges for decision makers. In addition finding funding for the selected portfolio increases the complexity.

The process of selecting Project portfolios is a complex task, which passes through various stages until it reaches the point of selecting the optimal portfolio [Galeno, 2008]. To invest in a project, companies look for its own available investments capital, banks, markets, and partners in Joint Venture.

This paper presents a framework for portfolio selection with Enhanced Oil Recovery (EOR) projects funding option including Joint Ventures, based on the Markowitz model.

The methodology is applied to a set of four projects in oil and gas business. The outputs with risk exposure are compared to risk-free using Markowitz models. The results show that the framework with the risk management models can be used for EOR portfolio selections with funding option and for joint venture equities determination.
Investigation of Different I-WAG Schemes Toward Optimization of Displacement Efficiency
Authors: Mousavi Mirkalaei S. Mousa , Hosseini S. Javad , Masoudi Rahim , Ataei Abdolrahim , Demiral Birol M. , Karkooti Hooman
Published: July 2011

The success of the hydrocarbon recovery improvement via Water Alternative Gas injection process is closely related to the microscopic displacement and macroscopic sweep efficiency. Effectiveness of the successive displacements by water and gas injections, maximizing the three phase zones by optimum force balancing in the reservoir, WAG injection cycle, double displacement and film drainage process are among the important parameters that affect the sweep and displacement efficiency in WAG process. Water and gas injection scheme play an important role in optimization of these parameters. Different schemes of WAG injection have been reported in open literature including gas injection up dip, water injection down dip and vice versa.

In this paper, the efficiency of various WAG injection schemes toward improvement of the above important parameters will be presented. Detailed theoretical investigation and simulation study are conducted. A new injection scheme is proposed. In the proposed methodology, water is injected from down dip and gas is injected from up dip in the first cycle. In the second cycle, gas is injected from down dip and water is injected from up dip. Water and gas injection location will alternatively change in each cycle of injection. Different design parameters are considered and studied including mobility ratio between water and oil phases, location of the water and the gas injectors, injection rate, WAG injection cycle. The results show that the proposed methodology has significant improvement on the displacement efficiency and three phase zone size and hence yield higher hydrocarbon recovery.
17 Years Development of Artificial Lift Technology in ASP Flooding in Daqing Oilfield
Authors: Yang Yonghua , Zhou Wanfu , Shi Guochen , Gang Cao , Wang Guoqing , Sun Chunlong , Qiang Li , Zhao Yunlong , Zhao Changming , Bai Wenguang , Wu Miao , Li Yanfei , Zhang Ming , Li Jinling , Ma Zhiquan , Xu Wenlin
Published: July 2011

To date, ASP flooding has been applied in commercial test in Daqing Oilfield for 17 years. From the beginning of the test, scaling issue in downhole artificial lift equipments had been realized as one of the most difficult problems in ASP flooding which resulted in high pump failure rate and operation cost. Therefore, the scaling principle in producers was studied in order to create a scaling risk analysis and risk prediction mechanism. In addition, Based on numerous laboratory study and field trial, a series of anti-scaling artificial lift techniques were developed as well, including surface material modification technique, special pump design, chemical scaling remover, etc.

Due to the considerable diversity of scaling phenomena in different blocks, different period and different wells, the anti-scaling artificial lift strategy was required to be adjusted respectively. Consequently, an innovative anti-scaling artificial lift methodology was created for different ASP flooding areas in Daqing Oilfield. This methodology was applied in 102 wells, both in beam pumping wells and PCP wells. The averaged running lives of artificial lift systems were improved from less than 30 days to over 300 days.

This paper detailed the developments of innovative artificial lift technology in ASP flooding in Daqing Oilfield. These new developments will effectively propel the commercial application of ASP flooding in petroleum industry.
Reservoir Characterization and Estimation of Remaining Oil Saturation using NMR logs for Optimizing a CO2 Flood: A Pilot Study
Authors: Ramakrishna Sandeep , Murphy Eric , Balliet Ron , Sullivan Lonnie , Barclay Kathleen , Schutte Raymond
Published: July 2011

Reinvestment in, and the rejuvenation of, aging oil fields are becoming increasingly commonplace. Because the price of oil has stabilized at an equitable value and enhanced oil recovery methods have been proven, previously-depleted oil reservoirs are being revisited to determine their potential for tertiary recovery by means of CO2 flooding. Accurate determinations of unswept oil and permeability distribution within the reservoir are critical elements in understanding and optimizing the CO2 flood. This paper presents a pilot study in utilization of NMR logging in the redevelopment of a field that has been waterflooded since 1953.

These mature reservoirs pose well-known challenges for formation evaluation. Resistivity-based saturation models are inadequate and uncertain because of previous waterfloods and variable formation water salinity (Rw) values. The variations in grain size and the onlapping of sand bodies cause uncertainty with the use of a porosity-permeability transform to estimate permeability.

These challenges must be overcome for optimal well placement, infill drilling, CO2 flood design, and other reservoir management practices. The standard logging suite for newly-drilled wells, triple combo and nuclear magnetic resonance (NMR), has evolved to address many of these challenges.

This paper presents a pilot study that demonstrates the effectiveness of NMR logs for reservoir characterization. These reservoirs were evaluated for estimating formation porosity, bound and moveable fluid volumes, permeability, and remaining oil saturations. The log data were compared and calibrated with X-ray diffraction (XRD), Specialized Core Analysis (SCAL), and Capillary Pressure data from core. Pore-size distribution from NMR has been used to identify facies changes and for geomodeling purposes. Variations in the facies and the distribution of the sand bodies have been correlated to 3D seismic data. This has helped with the accurate mapping of the reservoir units to understand sweep efficiency. Production results are used to validate the log interpretations. A similar method can be used in other aging oil fields and to evaluate the development plan of a CO2 flood.
Direct Visualization of Designer Water Flooding in Model Experiments
Authors: Cense A. W. , Berg S.. , Jansen E.. , Bakker K..
Published: July 2011

Increasing oil production by injection of designer water – also known as low salinity water – into a reservoir has recently attracted substantial attention from the oil producing community. The phenomenon has been studied by many researchers and low salinity water flooding is currently being applied in the field. On a macroscopic level, the effect can be parameterized as effective wettability modification to a more water-wet state but on a microscopic level, the effect is still not very well understood.

Most researchers agree that in sandstone rock, the mechanism is related to clay minerals but most of the experimental evidence is provided on the macroscopic scale (core flooding experiments) or even the field scale. Observations are not fully consistent and the predictability of the effect is limited. In a preceding publication [Petrophysics 2010, 51(5), 314–322] direct experimental evidence was provided for the detachment of oil droplets from a clay substrate upon exposure to low salinity brine.

The brine salinity for designer water flooding falls within a narrow window of opportunity: when too high, no additional oil production is observed; when too low, clay swelling and/or deflocculation may result in formation damage in the field. This raises the question whether there is a regime where oil is released with no or only minor formation damage and what the optimum salinity level for this would be. In this follow-up study, experiments are conducted on montmorillonite clay (which is a swelling clay belonging to the group of smectite clays) where the amount of released oil and the degree of formation damage are studied as a function of the salinity level. Starting at very high salinity (26,000 mg/L totally dissolved solids, TDS) no release of oil was observed and the clays remained stable. At very low salinity (2,000 mg/L TDS), up to 30% of the oil was released accompanied by substantial formation damage. There is, however, an intermediate salinity regime between 6,000 and 15,000 mg/L TDS where the formation damage is only very minor or not visible at all and still 10-30% of the initially attached oil is released. This is the regime of interest for field applications, although salinity levels have to be evaluated for the type of clay present in the formation rock.
Alkaline Steam Foam: Concepts and Experimental Results
Authors: Lau Hon Chung
Published: July 2011

Experimental studies have shown that the steam foam process can be significantly enhanced by injecting a suitably formulated alkali-surfactant mixture in the aqueous phase of steam. Emulsion screening tests, corefloods and flow visualization experiments using an alpha olefin sulfonate (AOS) surfactant with 16 to 18 carbon, Na2CO3 and a heavy Californian crude have shown that alkaline steam foam offers significant advantages over regular steam foam by combining the benefits of thermal and chemical enhanced oil recovery (EOR) processes.

Firstly, Na2CO3 reduces surfactant consumption by adsorption by rendering the clay surface more negatively charged. Secondly, by precipitating divalent ions that get ion-exchanged off the clays, Na2CO3 reduces surfactant consumption by precipitation. Thirdly, a suitably formulated alkali-surfactant system reduces the oil-water interfacial tension (IFT) sufficiently to enable the heavy oil to be emulsified into the aqueous phase in the presence of steam. This oil-in-water emulsion is less viscous than that of the oil and can be readily transported. Consequently, the residual oil saturation is reduced to that below steam. Fourthly, this lower residual oil saturation reduces the destabilizing effect of oil on foam resulting in stronger steam foam that provides better mobility control than regular steam foam. Therefore, it has the potential to further reduce steam gravity override. Fifthly, the reduction in gravity override also reduces loss of heat to the cap rock. Steam utilization is thereby improved.

When applied to steam drive, cyclic steam soaks and steam-assisted gravity drainage (SAGD) processes, alkaline steam foam has the benefits of increasing foam propagate rate, improving mobility control, improving steam utilization and reducing the residual oil saturation. In the cases of steam soaks and SAGD, it also increases the gravity drainage rate of oil by reducing the effective oil viscosity through emulsification.
An Alternate Simplified Approach For Selecting Enhanced Oil Recovery Technologies Using Analogs And Hubbert Peak Theory
Authors: Ortiz Volcan Jose Luis , Blanco Ronelba Isabel , Djotaroeno Diane Sirikit
Published: July 2011

Selecting the optimum combination of enhanced oil recovery (EOR) technologies is a critical activity during preparation of a successful business plan. This is usually accomplished by using protocols with technical parameters at reservoir formation levels from which candidates EOR technologies are screened and then subject to investment and risk assessment evaluation for final decision by management.

The previous approach very often misses the effect of operational expenditures, wearing and failure related downtime and learning curve during pilot testing on oil recovery efficiency and EOR economics which is usually expressed in terms of net present value.

This paper proposes an alternate simplified approach using an acceptable representation of life cycle phases of natural and physical asset components functioning as a system of assets for a particular subject reservoir. We introduce a taxonomic solution to help in classifying candidates EOR technologies. Four major functional indices are used for handling uncertainties and risks using data from analogs for defined scenarios in the subject reservoir: 1-Accesability) Footprint effects for constructing and operating physical assets (wells and surface infrastructure), 2-Contactability) Volume of resources contacted from a surface location, 3-Produceability) Volume of producible resources from drainage area to surface and 4- Effectiveness) Combined effect of availability, reliability, maintainability y and capability in efficiency of oil recovery.

The four major indices are cross referenced with life cycle cost (LCC) and estimated ultimate recovery (EUR) using Hubbert peak oil theory and the Petroleum Resources Management System classification for resources and reserves. Uncertainties and risks are modeled with Monte Carlo simulation (MCS) or Systems Dynamics (SD) depending on the complexity of the system of assets.

We present examples using synthetic data to illustrate the method.

This approach is worth using during EOR project definition and planning as an alternate to complex data hungry methods.
A Case Study: A Successful Steam Flooding Project to Enhance Oil Recovery of Low-permeability, Light-oil Waterflooding Reservoir
Authors: Wu Shuhong , Han Min , Ma Desheng , Wu Yongbin , Yu Qian , Chunli Yao , Dehuang Shen
Published: July 2011

Steam flooding, one of commercial technologies widely used to develop heavy oil reservoir, has brought reservoir engineer’s attention to improve performance of waterflooding, light oil reservoir and enhance its oil recovery. In Cy reservoir of Daqing oil field, a steam flooding project is successfully going on to enhance the oil recovery after waterflooding. Cy reservoir is a typical low-permeability, light-oil reservoir with depth of 1000m, an average permeability around 8 md and a typical porosity of 16%, oil viscosity of 16~95mpa.s.

Cy reservoir came into development in 1995 under waterflooding. However, waterflooding has suffered from low water injectivity, poor sweep, and poor injector-to-producer communication. Only 10% of oil in place has been produced during 10 years’ waterflooding. In 2007, steam flooding was utilized to improve the performance and enhance the oil recovery. The steam flooding project shows promising results. The response to steam injection is prompt and significant. The injectivity is doubled and productivity is almost tripled. The oil-steam-ratio is around 0.3. The incremental recovery is predicted to be over 10%.

The paper will firstly brief production history of waterlfooding. Secondly, the paper will detail steam injection and analyze its performance and influence factors.The paper will also discuss mechanisms, strategies as well as barriers and difficulties to high recovery of steam flooding in such waterflooding, light oil, low permeable reservoir andl also detail reservoir engineering study, such as development manner, injection and production system, and its physical and numerical simulation. The steam flooding project shows us that steam injection has great potential in improving injection and production profiles, increasing productivity and enhancing oil recovery.
Numerical Simulation Study of SAGD Experiment and Investigating Possibility of Solvent Co-Injection
Authors: Ashrafi Mohammad , Souraki Yaser , Karimaie Hassan , Torsaeter Ole , Kleppe Jon
Published: July 2011

Bitumen resources constitute a high portion of the total world oil resources. The main recovery mechanism for these high viscous fluids is to reduce their viscosity by the application of heat, mostly by introducing steam.

Among different steam injection schemes, steam assisted gravity drainage (SAGD) has become the method of choice applicable to bitumen and oil sand reservoirs. In these extra heavy oil resources, the reservoir has almost no injectivity due to high oil viscosity, and therefore conventional steam flooding is hard to conduct. SAGD, however, reduces the viscosity of bitumen in place and the heated bitumen drains due to gravity forces towards the production well and is then being produced. Recently hybrid processes are attracting more attentions in the industry. These processes benefit from co-injection of a solvent together with steam. The solvent can diffuse into the bitumen and make it even lighter by reducing the viscosity.

Our simulation study is based on the experimental work done by Chung (1988) and the simulation model of this experiment by Chow (1993). Chung’s physical experiment was a 2-D model to simulate SAGD experiment in laboratory. The Chung’s experiment was done with Cold Lake crude oil. A reservoir simulation model was built using a numerical thermal reservoir simulator. The model was then tested and validated with Chung’s physical model. Having a valid model, sensitivity analysis was run to examine the effect of different simulation parameters on recovery and steam oil ratio.

The sensitivity parameters tested are steam temperature and quality, the porosity of the model, different well placement schemes, and the effect of shale barrier. Different steam temperatures and qualities were examined. The best injection condition was found to be 130 °C and 90% quality, beyond which no increased recovery was achieved. Different injector and producer placements were tested. Placing injector and producer diagonally in the model showed the best horizontal sweep efficiency in the laboratory model. Horizontal shale barrier had a dramatic negative effect on the oil recovery. Vertical shale, however, had a smaller effect. This is because in horizontal case the steam chamber cannot reach to the top layers. Porosity was found to be inversely proportional to the oil recovery and steam oil ratio. Results showed that solvent can help to improve oil recovery and steam-oil ratio. In addition most of the injected solvent could be recovered from production stream. Sensitivity analyses on solvent type and concentration indicated significant effects on performance of process. Among the solvents used in this study, hexane showed the best recovery performance.
An Integrated EOR Successfully Applied In Chang-6 Ultra-Low Permeability Reservoir
Authors: Guo Xiao , Yang Yue
Published: July 2011

The Chang-6 reservoir is characterized by low porosity, ultra-low permeability and low Deliverability. At present, water injection pilot only occupied 3.6% of the whole reservoir area. Most of wells will been flooded rapidly once water injection was conducted. How to enhance the oil well production and crude oil recovery is of great strategic significance for guaranteeing the sustained and sTab.le development of YanChang oil field Co.ltd. In this paper, a series of empirical formula was compared and oil recovery of Chang-6 reservoir was determined at 13.9%. The starting pressure gradient and stresssensitive experiments were carried out. The result suggested that the influence of stress-sensitive cannot be ignored. Based on infiltrating fluid experiments and considering the stress sensitivity, a comprehensive research of numerical simulation for the injection zone was conducted to determine the residual oil saturation and demonstrate the feasibility of cyclic water injection, continuous water injection and surfactant injection for EOR. In addition, a suit of clean-fracturing fluid of surfactant acting agent was invented and a foam fluid system was optimized for Chang6 low-permeability reservoir. This study and pilot show that invented clean-fracturing fluid and optimized foam fluid system was effective for ultra-low permeability reservoir.
Polymer Flood Simulation in a Heavy Oil Field: Offshore Niger-Delta Experience
Authors: Mogbo Obuekwe
Published: July 2011

A simulation case study is described which illustrates the application of polymer flooding to an offshore heavy-oil reservoir within the Niger Delta. This shallow depth offshore reservoir has excellent reservoir quality (up to 39% porosity and 6D in good sands). It has 3 different panels, laminations in sand sequences and contains biodegraded fluid of varying fluid viscosities (2 to 16cp under reservoir conditions). Bubble point is close to reservoir pressure necessitating injection form start of field life to maintain reservoir pressure.

The paper begins by a brief discussion of the mechanics of polymer flooding and its simulation methodology: the effect of water salinity, choke shear degradation and thermal degradation on injectant mixture viscosity is determined from detailed Laboratory studies. Other simulation input parameters like permeability reduction related to adsorption and residual resistance factor are also estimated per facies. All data are implemented as lookup tables in the Polymer option of an available commercial simulator. High injectivity potential (unconsolidated sand dilatance regime) is simulated to ensure that as much polymer as required was injected in High BHP regime without fracturing the reservoir cap rock.

Several full field scale sensitivities were run in an experimental design approach in an effort to optimize the injection strategy and flood pattern for both a water injection case and then the polymer flood case. All producers and injectors are either horizontal wells or deviated wells. The polymer flood effect is recognized and analysed: Best case incremental oil recovery was 7% with earlier polymer injection allowing for greatest incremental recovery. Significant Plateau extension and delayed water breakthrough were noted.

The results show that polymer flooding is economically justified for this field. This paper also discusses how adequate pre-project preparation and pilot-testing brings added value during the life-cycle of Heavy-Oil fields
Case Study: Numerical Simulation of Surfactant Flooding in Low Permeability Oil Field
Authors: Xu Feng , Guo Xiao , Wang Wanbin , Zhang Nan , Jia Sha , Wang Xiaoqin
Published: July 2011

Low permeability reservoir occupies an important position in China’s petroleum industry, as an important oil industry resource over a period of time in future, which helps to increase reserves and production. Surfactant flooding is one of the most effective ways to improve development effect in the low permeability reservoirs, which can reduce the injection pressure and increase injection rate, thereby enhancing oil recovery. Common mechanisms that how the surfactants enhance oil recovery are discussed in the paper. On the basis of assumptions, a seepage model of surfactant flooding was built to describe the complex process. Experiments was done to determine the surfactant’s performance, such as the relationship between surfactant concentration and oil/water interfacial tension, the relationship between surfactant concentration and rock adsorbance, and the relationship between surfactant concentration and water viscosity. Take the Yanchang low permeability reservoir for example, where the study of surfactant flooding is conducted after the optimal water injection plan to evaluate the effect of different surfactant concentration on the development results in the low permeability reservoir. The simulation results show that surfactant flooding has the role of enhancing oil recovery, and that the optimal surfactant concentration is 2%, which can enhance oil recovery by the percentage of 0.22.
Sustainable Surfactants in Enhanced Oil Recovery
Authors: Santa Monika , Alvarez-Jürgenson Gabriela , Busch Stefan , Birnbrich Paul , Spindler Christian , Brodt Gregor
Published: July 2011

Alkyl polyglucosides (APGs) are recognised as sustainable surfactants based on natural raw materials. They exhibit a low ecotoxicity profile and are therefore already used in different oil field applications. In this paper it is shown that APGs have superior solubility properties in high salinity environments. The interfacial tension of crude/brine systems can be significantly lowered even in high salinity brines. The performance of APGs can be improved by optimising the hydrophobic as well as the hydrophilic part of the surfactant. In contrast to standard surfactants used in EOR applications the performance of APGs is not reduced under elevated temperature or high salinity conditions. Their performance is not influenced by typical salinity and temperature gradients as can occur in the reservoir. Moreover, microemulsions can be formed even under high salinity and elevated temperature if APGs are used together with co-solvents.
Increasing Cold Lake Recovery by Adapting Steamflood Principles to a Bitumen Reservoir
Authors: Stark Shane D.
Published: July 2011

The Cold Lake project, located in Alberta, Canada, is the world’s largest heavy oil in situ thermal development, with production of about 24,000 m3/d (150 kB/d) of oil from more than 4500 wells. In 2009, Cold Lake produced its one billionth barrel (160 million m3) of heavy oil.

The world class Cold Lake hydrocarbon resource is characterized as a bitumen deposit, featuring in situ viscosities in excess of 100,000 mPa-s. Early depletion plans envisioned a thermal recovery process similar to the steamflood technologies employed to recover heavy oil in California’s San Joaquin Valley. The order of magnitude difference between Cold Lake and California in-situ viscosities, however, severely limits steam injectivity below fracture pressure, necessitating the development of a Cold Lake specific cyclic steam stimulation (CSS) process throughout the 1980s.

Continual process optimization combined with infill drilling has resulted in a progressive increase in expected bitumen recovery from 13% to greater than 40% of effective bitumen in place (EBIP). A multi-disciplinary reservoir management effort conducted over the last several years has provided the view that Cold Lake recovery levels may potentially be increased to over 65% by adapting steamflood principles to mature CSS areas of the reservoir: reservoir simulation was used to define the steamflood opportunity’s technical and economic viabilityan extensive selection process based on several criteria was used to select an appropriate field trial locationtrial plans were reviewed with experts with California steamflood experiencea Cold Lake steamflood field trail was designed, implemented and successfully operated for three years

As cyclic process efficiency declines due to lack of steam confinement, steamflood technologies become an attractive recovery scheme in mature Cold Lake reservoir by capitalizing on large scale inter-well communication while focusing on gravity drainage: trial results to date are encouraging and in agreement with performance predictionssuccess to date has benefited from the evaluation of prior trails at Cold Lake, review of global steamflood analogs and extensive reservoir simulation efforts prior to field trial design and implementationsteam confinement is a significant but manageable operational challenge