bluuebunny/crossref_metadata_2025 huggingface dataset:
EOS Modeling, The First Step in Detailed EOR Potential Evaluation - A Case Study
Authors: Sah Pashupati , Pedersen Karen Schou , Azeem Shaikh Jawad
Published: July 2011

The paper presents an Equation-of-State (EOS) modeling work carried out for a Middle East reservoir fluid for which gas injection was considered for increasing ultimate recovery. The aim of the work was to develop an EOS model that would accurately reproduce the phase behavior in a reservoir on injection of either a hydrocarbon gas (mix of gas condensate and associated rich gas) or a CO2 rich gas. A single EOS model was developed, which provided a good match of data for both injection gases. This EOS model enables compositional reservoir simulation studies to be carried out comparing and contrasting the recovery from the field with each of the two injection gases.

Extensive PVT data was available and to be matched by a 9-component ‘lumped’ EOS model. Available data included classical PVT data as well as gas injection (EOR) data including solubility swelling, equilibrium contact and slim tube tests. A major challenge was to develop a model which, in addition to classical PVT data, which can easily be regressed to, also matched slim tube minimum miscibility pressures (MMPs). A multi-component tie-line method was used considering combined vaporizing/condensing drives, and the tie-line MMP was afterwards verified using a cell-to-cell simulator.

Depth gradient simulations indicated that the transition from liquid-like to vapor-like properties in the reservoir did not take place through a sharp gas-oil contact (GOC), but happened continuously in a‘transition zone’. An EOS model neglecting such‘transition zones’ or simulating a sharp gas-oil contact may lead to severe misinterpretations in reservoir simulations. A segregation model based on irreversible thermodynamics was used to investigate the influence of an observed vertical temperature gradient on the compositional variation with depth.
Estimates Of Surfactant Concentration Used For EOR In Daqing Oilfield Low Permeability Oil Reservoir
Authors: Hongwei Yu , Taoping Chen , Ming Gao , Jinshan Liu , Jijun Liu
Published: July 2011

In low permeable reservoirs of Daqing oilfield, the water drive recovery efficiency is low and other technology, such as polymer flooding, which have been successfully put into use for largely enhance oil recovery in medium or high permeable reservoirs could not be applied in the low ones due to high injection pressure.

Based on the description of characteristics and surfactant flooding mechanism, the practical conditions of Daqing oilfield low permeable reservoirs were simulated. Some experimental EOR studies of new surfactant named SY used for flooding have been done in the lab with low permeable artificial and natural cores. In a constant temperature, after the water flooding, 5 different concentrations (0.1%, 0.2%, 0.3%, 0.4% and 0.5%) of SY surfactant were used for flooding.

The result shows that the displacement efficiency of the SY surfactant is different under 5 concentrations, at the concentration of 0.5%, the recovery efficiency could be enhanced greatly, by 12.2%, and at the concentration of 0.3% and 0.4%, the recovery could be enhanced by 11.78% and 11.86%, nearly that of the concentration of 0.5%, but at the concentration of 0.1% and 0.2%, the recovery could only be enhanced by 5.23% and 6.85%.Because of the low surfactant usage and good oil recovery enhancing characteristics, 0.3% is the best concentration to be used. Reservoir simulation predicts that if the concentration of 0.3% can be used in low permeable reservoir C-1 block in Daqing oilfield, the recovery can be enhanced by 3.5% in 3 years flooding, and the final recovery can be enhanced by 11.52%.

The study has reference value to low permeable oilfield which will use the new type of SY surfactant to enhance recovery.
Study on the Safety Geology Sequestration after CO2 Displacement in Low Permeability Oil Reservoir
Authors: Hong-wei Yu , Ping-ping Shen , Yan-yao Shi , Yong-zhi Yang , Jing-yao Wang , Hong-wei Yu
Published: July 2011

For the purposes of winning economic performance and environmental performance, the application of CO2 displacement might be a viable option due to enhancing oil recovery significantly and sequestrating part of CO2 permanently.

Molecular diffusion is the key migration style of sequestrated CO2 due to concentration gradient in geologic body, so in the process of CO2 concentration goes to a balance condition, the sealing performance of cap rock for CO2 is influenced by some extent.

According to actual geologic parameters of Jilin CO2 flooding pilot test, CO2 diffusion coefficients were investigated in cores of super-low permeability saturated with in place oil under both miscible and immiscible pressure. Results obtained from these experiments were used to gas saturation field prediction for 1000 years after CO2 flooding on 12 homogenetic models considering immiscible, near-miscible and miscible conditions and cap rock thickness from 10m to 100m.Based on the prediction, CO2 geology sequestration safety template was built considering both miscible condition and the thickness of cap rock, which allows getting optimum reservoir and geological parameters for CO2 sequestration.

This research has reference value on the evaluation for CO2 geology sequestration ability and safety in low permeability oil reservoir.
Optimizing Simulation Studies for Miscible Gas Injection Process Using Horizontal Wells
Authors: Zakaria Ahmed S.
Published: July 2011

The use of Horizontal well has been increasing very rapidly throughout the oil industry and its applicability is now extended to the secondary and tertiary recovery processes. In this paper, a study on mature oil field case has been made to assess the technical feasibility of miscible gas injection using horizontal wells and to investigate the impact of gas injection horizontal wells on ultimate oil recovery. A reservoir model using 3-D compositional equation of state simulator is built to carry out different development scenarios to optimize the field development and increase the oil recovery using miscible gas injection process. The model is used to investigate the impact of using different combinations of horizontal and vertical injection and production wells on the performance of the process. The impact of alternative development scenarios on oil recovery, plateau oil production rate, and fluid saturation distribution are evaluated. The results show that the use of horizontal gas injection wells resulted in increase in cumulative oil recovery and gives better sweep efficiency.

A sensitivity study is also presented in this paper to evaluate the parameters that affect the performance of the horizontal well pattern used in miscible gas injection process. The study emphasized on the horizontal permeability, permeability anisotropy, horizontal well length. From the simulation results, the model is found to be most sensitive to permeability anisotropy followed by horizontal permeability then to horizontal well Length. Thus it is recommended that these parameters must be properly estimated prior to use in simulating miscible gas injection process using horizontal well pattern.
Selecting the "Right" ASP Model by History Matching Coreflood Experiments
Authors: Karpan V.. , Farajzadeh R.. , Zarubinska M.. , Dijk H.. , Matsuura T.. , Stoll M..
Published: July 2011

In order to design and analyze Alkaline Surfactant Polymer (ASP) pilots and to generate reliable ASP field forecasts a robust scalable modeling workflow for the ASP process is required. A starting point of such a workflow is to carry out ASP coreflood tests and history match those using numerical models. This allows validation of the models and generates a set of chemical flood parameters that can be used for field-scale simulation forecasts.

It is well established that lowering of interfacial tension due to maximum of in-situ generated soap with injected surfactant and improved mobility control due to the polymer play a crucial role in the ASP process. Therefore, all models for the ASP process take into account these mechanisms in one way or the other. However, ASP models can differ in the detail in which (geo-) chemical reactions and the phase behavior are addressed. Inclusion of the more details into the numerical model could result in better understanding and more accurate prediction, but it comes at a price, viz., it requires more measured input data and increases computational time. Thus, depending on the accuracy requirements, available experimental data and time the modeling of ASP flood can be performed using different simulation approaches.

This paper describes several modeling approaches for ASP. We start with a brief description of these methods and their input requirements. Then we compare the ASP coreflood simulation results demonstrating the advantages and disadvantages of presented approaches. We also demonstrate that both ASP models can be applied at the field level by simulating an ASP flood in a sector model. Finally we give some recommendations and guidelines on how and when the proposed models should be used.
Quantitative Uncertainty Estimation and Dynamic Model Updating for Improved Oil Recovery
Authors: Maucec Marko , Cullick Stan , Shi Genbao
Published: July 2011

Optimal Improved Oil Recovery (IOR) depends significantly on the ability to estimate volumes and locations of bypassed oil from available historical data. Assisted simulation history-matching techniques are being used to estimate remaining reserves volumes and locations. This paper presents an approach to history match that more accurately captures model uncertainty. The novelty lies in direct interfacing between the geological modeling software and a forward simulator with the rapid generation of model updates in wave-number domain.

We describe a Bayesian workflow based on two-step Markov chain Monte Carlo (MCMC) inversion. Arguably, the MCMC methods statistically provide the most rigorous way of sampling posterior distribution, but when deployed in direct simulation, suffer from high computational cost. We outline an approach where the proxy model is guided by streamline-based sensitivities, dispensing with the need to run forward simulation for every model realization. We generate an ensemble of sufficiently diverse static model realizations at the high-resolution geological scale that generates more accurate results by obeying known geostatistics (variograms) and well constraints. An efficient model parameterization and updating is described for rapid characterization of the main features of geologic uncertainty space: structural framework, stratigraphic layering, facies distribution, and petrophysical properties.

We validate the workflow on a case study combining geological model with ~900k cells, four different depositional environments and 30 wells with 10-year water-flood history. The method can be used for successfully identifying the highest potential to capture bypassed oil and for implementing IOR. A history-match method is presented that has potential to lead to better IOR decisions and results through more accurate simulation models and inherent quantification of uncertainty.
Visualization of CO2 Displacement Process under Gravity Domination
Authors: Mohiuddin Zeeshan , Haghighi Manouchehr
Published: July 2011

The gravity dominated CO2 injection has received increased attention in the oil fields as it utilizes gravity force to stably displace the remaining oil after primary and/or secondary recovery. Effect of gravity is also important in some CO2 sequestration in aquifers. To visualize the fluid-solid interaction mechanisms at pore scale and to determine the controlling factors for a stable gravity dominated process, parameters such as fluid and porous media properties should be evaluated. The visualization of displacement process at the pore level could help to identify the critical range of controlling parameters. These visual experimental results could validate the modelling of fluid flow at pore scale. Therefore, an experimental study was conducted using a glass micromodel and visual results have been analysed. The details of experimental setup including micromodel construction, holding rig and the instrumentation have been addressed in this paper.

The experiments were conducted using CO2 injection to displace water at various rates under different gravity conditions. This displacement under pressure slightly above the atmospheric conditions has been characterized as partial miscible displacement. Experimental results determined the relationship of porous media characteristics such as dip angle and porous medium heterogeneities on the process at pore scale. The results were analysed using dimensionless Darcy Rayleigh number and mobility ratio to extend the results at larger scales and different fluids. The experimental results show that Darcy-Rayleigh number is proportional to the displacement efficiency however; at moderate flow rates and the dip angle of 45°, lower recovery was observed compared to horizontal case. Also at dip angle of 45° and with higher viscosity of the defending fluid (lower mobility ratio) a more stable process was observed.
Laboratory Assessment and Field Pilot of Near Miscible CO2 Injection for IOR and Storage in a Tight Oil Reservoir of ShengLi Oilfield China
Authors: Ren Bo , Xu Yang , Niu Baolun , Ren Shaoran , Li Xiangliang , Guo Ping , Song Xinwang
Published: July 2011

Gas injection into tight oil reservoirs, as a secondary recovery technique, can be favorable and promising in terms of high gas injectivity and good displacement/sweeping efficiency over water injection. Particularly, CO2 injection is the best option due to its superior miscibility effect with oil and in consideration of geological storage of the greenhouse gas. In this study, CO2 injection into a tight oil reservoir for IOR is assessed and a pilot project is underway. The reservoir is located in the G89 Block of Shengli Oilfield East China, which has very poor water injectivity due to very low permeability of less than 5 mD in average, and has been producing via natural depletion since 2005. The original reservoir pressure was over 40 MPa, and the reservoir temperature of 126  . A CO2 injection and storage program has been proposed, and CO2 will be from a coal-fired power plant 30 km away under a Sinopec’s CCS (Carbon Capture and Storage) scheme. Laboratory investigation includes PVT experiments, slim tube test and core flooding/displacement experiments, in order to study the miscibility effect and displacement efficiency via CO2 injection at various conditions. Reservoir simulations were performed to predict the IOR potentials of CO2 injection at different pressures, namely at immiscible, miscible and near-miscible modes. The MMP (Minimum Miscibility Pressure) of the reservoir oil is determined as over 29 MPa, while the reservoir pressure at the beginning of CO2 injection was around 23 MPa after several years’ depletion. Therefore, CO2 flooding at a near miscible mode will prevail. A field pilot of CO2 injection at current reservoir conditions (at near-miscible mode) is designed and its performance is presented in the paper.
Comprehensive EOR Screening and Pilot Test for Thar Jath Heavy Oil Field, Sudan
Authors: Suliman Abdalla Elhag , Ngah Ab. Wahab , Basbar Ashraf Elfadil , Anua Nor Aidil , Hashim Salaheldin Tawfig
Published: July 2011

Many of Sudan’s large oil fields suffer from low recovery factors and decline in primary production due to low oil gravity (<22 API) and viscosities above 100 cP. Many wells experienced premature water production. As such, Enhanced Oil Recovery project seems to be the option to improve oil recovery in Sudan.

Thar Jath field contains in excess of 1.2 billion STOIIP, 75% of the STOIIP comprises 20° API oil with 120–160 cP viscosity while the remaining STOIIP comprises 16° API with viscosity > 680 cP viscosity. The Full Field Review which was carried out through 2009 recognized that primary and secondary recovery could only recover, at best, 9.0% of the STOIIP with infill drilling. As such, a considerable number of Enhanced Oil Recovery (EOR) techniques have been assessed in order to recommend suitable EOR development project for the field, and to position the field as leading the way in Sudan. In the absence of a miscible gas option, dynamic reservoir simulation schemes were developed for the natural depletion, water flood, chemical, thermal and immiscible gas methods.

The three most promising techniques; ASP, steam flood/CSS and in-situ combustion were developed to optimize pattern spacing, injection rates and pressures for each technique. Thereafter, facilities schemes and notional costs were developed so that economic viability could be assessed to select the most preferred technique going forward. EOR has been found to be economically and technically feasible with highest economic recovery across all reservoirs from Steam technique. There is scope for thermal recovery to take recovery factor above 40% overall. The pilot test design study is on going with the objective to proof the concept and confirm scope of recovery from steam flooding prior to full field implementation.
The Study of Oil Displacement Characteristics of CDG and Polymer Flooding
Authors: Zhidong Guo , Chang Harry L. , Chengyong Fan , Jinliang Li , Weihua Hou , Dianguo Sun
Published: July 2011

The Colloidal Dispersion Gel (CDG) technology, sharing multiple similarities with polymer flooding, is developed(1) for in-depth profile modification. However, due to the differences in chemical type and concentration, molecular structure and mechanisms, the displacement processes between CDG and polymer are different. The injection capacity of the two processes are about the same, but polymer flooding features large injection increase amplitude, quick pressure increase in initial period and quick decrease for subsequent flooding pressure; while CDG injection features a slower and gradual increase and decrease. The oil recovery effect for polymer flooding is mainly realized during the process of polymer injection, featuring quick water cut decrease and fairly quick increase as well quick water cut increase for subsequent water flooding; the oil displacement effect of CDG is equivalent of that for polymer flooding during chemical injection, but performs much better than polymer during subsequent water flooding. During the initial stage of the CDG injection, the water cut shows multiple stages of decline and then shows a slow increase during the water drive. In addition, water cuts in producers were stabilized for a long period of time. The production cycle for polymer flooding in a pattern with 250 meters distance between injection and production wells is usually about 6 years, while the CDG process lasted over 10 years. Under similar geological conditions, the chemical injection amount for CDG profile modification is 20% less than that of the polymer flooding but the increased oil recovery is about4% over the polymer flooding at the economic limit.
Nabiye Cold Lake Expansion - Leveraging Technology to Create Success
Authors: Fawcett Heather L. , Kueh Sylvia , Sheng-Yuan Hsu , Liang Yueming , Scott George R. , Dittaro Larry M.
Published: July 2011

The Cold Lake development, located in Alberta, Canada, is the world’s largest heavy oil in situ thermal development. At Cold Lake, operated by Imperial Oil Resources, an ExxonMobil affiliate, the Cyclic Steam Stimulation (CSS) process is used to produce 23,500 m3/d (150 kB/d) of heavy oil. In 2009, Cold Lake produced its one billionth barrel (160 million m3) of heavy oil.

The Nabiye project will be the fifth central steam generation and fluid processing hub added at Cold Lake. Nabiye (Dené for Otter) continues the historical Cold Lake development concept of maximizing value through the utilization of a phased development strategy. Relative to current operations, the key reservoir difference at Nabiye is reduced pay thickness. Averaging 12 meters (40 feet), Nabiye pay is about half as thick as the initial pads of the previous expansion (Mahkeses). While reservoir of similar thickness as Nabiye is currently being developed as Productivity Maintenance pads to sustain production in the existing operation, the risk profile for Nabiye is higher because new plant investment is required.

As Cold Lake develops more challenging subsurface environments, more advanced reservoir engineering techniques must be employed to mitigate risk. This paper describes the extensive use of both thermal simulation and wellbore integrity modeling to complement analog performance prediction techniques.

This paper will demonstrate how the Nabiye project is effectively commercializing an unconventional resource by integrating analog performance data and advanced reservoir and geomechanical modeling. The application of (1) thermal simulation for performance prediction and (2) geomechanical modeling for steam strategy optimization will be presented.
Successful Story of Development and Optimization for Surfactant-Polymer Flooding in a Geologically Complex Reservoir
Authors: Dang Cuong T. , Chen Zhangxin , Nguyen Ngoc T. , Bae Wisup , Phung Thuoc H.
Published: July 2011

For mature reservoirs, surfactant-polymer (SP) flooding is an attractive alternative to conventional waterflooding. However, it is a complicated process and the performance of SP flooding in complex reservoirs requires an accurate model that represents the reservoir features, chemical properties, and displacement mechanisms. This paper presents a successful application of miscible-tertiary SP flooding in an extremely heterogeneous reservoir. First, a series of numerical simulations in both homogeneous and heterogeneous cases were investigated and analyzed by a CMG™ simulator. Then a mathematical model was developed based on the Langmuir isotherm theory in order to fully integrate adsorption phenomenon into a reservoir model for controlling and reducing this effect during the SP flooding process. Small of polymer/surfactant adsorption leads to a small amount of chemical required for injecting and decreases operational cost.

Based on the above achievements, SP flooding was successfully applied for White Tiger - the biggest offshore oil field with high heterogeneity and complex geological characteristics in the Viet Nam continental shelf. An optimal range of operated conditions that include polymer solution properties, injection pressure and injection rates are proposed with the objective of optimizing the SP process in the White Tiger field. The simulation results show that SP flooding is the best recovery schemes in comparison with waterflooding, pure polymer flooding and pure surfactant flooding. A significant increase in oil production has been achieved by the effect of surfactant and polymer which is a really successful evidence of SP flooding in complex reservoirs.
Planning for Increased Production through Integrated Well and Reservoir Surveillance in the Oman EOR Developments
Authors: Zwaan Marcel , Hartmans Rob , Saluja Jasmeet , Schoofs Stan , Rocco Guillermo , Adawi Rashid , Saadi Faisal , Lopez Jorge , Ita Joel , Mahani Hassan , Qiu Yuan , Rehling Johannes
Published: July 2011

PDO has implemented Enhanced Oil Recovery (EOR) methods including thermal, chemical and miscible gas injection projects in several fields. In the initial phase of these EOR projects, well and reservoir surveillance is key to increase the understanding of the effectiveness of the EOR processes in the various reservoirs. Well-planned and executed reservoir surveillance has proven in the past to add significantly to the production and ultimate recovery from reservoirs.

Because of progress in technology in areas of data acquisition, processing and modeling techniques, well and reservoir surveillance data are increasingly used to optimize EOR processes. However, the interpretation of all data and integration into well and reservoir management workflows is still challenging. This paper describes the ongoing development of workflows for the interpretation, modeling and integration of surveillance data in three EOR projects. The surveillance methods include geomechanical modeling, thermal reservoir modeling and monitoring through time-lapse seismic, surface deformation, microseismic, temperature, pressure and saturation logging.
Using Analog Reservoir Performance to Understand Type I Fractured Reservoir Behavior with Strong Water Drives
Authors: Meehan D. Nathan
Published: July 2011

Type I fractured reservoirs are those in which the matrix is impermeable and fractures provide essentially all of the storage capacity and the fluid-flow pathways in the reservoir. This paper summarizes an analog reservoir study that compared the performance of dozens of such reservoirs to understand their behavior when strong water drives are present and particularly when oil viscosities are moderately high. Most such reservoirs are basement or volcanic rocks; however, numerous analogous clastic and carbonate reservoirs have also been identified.

Recoveries in "Type I" reservoirs access a larger fraction of the oil-in-place in the fractures and very little matrix oil. Fracture recoveries can be expected to be very high (60 to 90% of the swept fracture volume) with extremely low recoveries in the matrix. Fracture porosities vary widely in fractured reservoirs and analogs may be poor sources of this information. Values of fracture porosity in excess of 1.0% are uncommon; however, some fields may have values up to about 3% or higher for certain fractured cherts.

Strong water drives can lead to high initial flow rates and relatively early water breakthrough; true Type I reservoirs may have very poor recoveries as a result. Horizontal wells often accelerate total recovery and may in fact lead to substantial incremental recovery. Heavier oils exacerbate early water breakthrough. Few reservoirs with significant fracturing were consistently fractured areally and with depth. Heterogeneity in fracturing is the rule and has few exceptions. In some many cases identifying the driving cause of spatial heterogeneity in fracture occurrence is the key to developing the field properly.

Water shutoff efforts around the world in highly fractured reservoirs are generally failures. Treatments that successfully shut off water often greatly reduce oil production. This is particularly true of horizontal wells and most true of uncemented liners and open holes. Only in cased and cemented vertical or horizontal wells is there a routine chance of shutting off completion intervals. In many such cases, profile control improvements are temporary as the unwanted fluid bypasses the near-wellbore shutoff area. Gas influx is generally more severe than water influx.

Horizontal well placement is critical in developing Type I reservoirs and is a function of reservoir management and fracture characterization. Multiple laterals offer attractive operational and cost alternatives. Overdrilling similar reservoirs appears to have occurred in quite a few fields. Example fields from around the world are compared using a variety of approaches including some unique comparisons of temperature logs and pressure transient analysis tests.
Field Experience from a Biotechnology Approach to Water Flood Improvement
Authors: Bauer B. G. , O’Dell R. J. , Marinello S. A. , Babcock J.. , Ishoey T.. , Sunde E..
Published: July 2011

This paper is based on a field implementation in the United States of a biological process for improving waterflood performance. The Activated Environment for Recovery Optimization ("AERO™") System is being developed by Glori in collaboration with Statoil and derives its roots from a microbial enhanced oil recovery technology developed and successfully implemented by Statoil offshore Norway. Unique among IOR technologies, AERO implementation requires virtually no capital investment and achieves high performance efficiencies at low operational cost. The simplicity of setup allows pilot project implementation creating a very low risk entry point for the operator.

A pilot project was selected for a controlled investigation of the performance and impact. Robust testing was done in both water and oil phases prior to treatment, confirming the potential for improved sweep and conformance from the project. Subsequent implementation resulted in decreased water cut and increased oil recovery observable both at the wellhead and allocated pilot levels.

This paper summarizes a rigorous analysis of the pilot project’s performance to date, concluding that the production improvement should be credited to the implementation of the AERO™ System.
Development and Optimization of Polymer Conformance Control Technology in Mature Reservoirs: Laboratory Experiments vs. Field Scale Simulation
Authors: Dang Cuong T. , Chen Zhangxin , Nguyen Ngoc T. , Bae Wisup , Phung Thuoc H.
Published: July 2011

Water shutoff in mature reservoirs is traditionally achieved with cross-linked gels. By blocking the areas already swept by water, subsequently injected water can sweep an unswept area of the reservoir and thereby increase the oil recovery. However, it is a complicated process and the performance of polymer gel flood in complex reservoirs requires an accurate model that represents the reservoir features, chemical properties, and displacement mechanisms.

This paper presents a successful investigation of polymer gel behavior from laboratory to full field scales. First, a series of laboratory experiments were conducted to achieve a deep understanding of polymer gel behavior. The results show that the polymer viscosity, gelation time, and gel strength strongly depend on reservoir temperature, polymer type, polymer concentration, cross-linker concentration, pH and salt concentration, which are the successful keys of a polymer conformance control process. The optimal values of these parameters are proposed for applying in a pilot test. A series of numerical simulations are performed to history match with experiment data and generate parameters for field scale simulation. The adsorption phenomenon is fully integrated into the reservoir model for controlling and reducing this effect during the polymer flooding process.

According to the laboratory results, polymer gel flooding was applied for White Tiger which is the biggest oil field in Viet Nam. After a long time of waterflooding, water production becomes a serious problem in this field. Polymer gel treatment is simulated in full field scale and the results show that it is an excellent candidate for conformance control. Water production decreases from 4,800m3/d to slightly less than 2,000m3/d, while a significant increase in oil production has been achieved from unswept zones. That is a really successful evidence of the polymer conformance control technology in heterogeneous reservoirs.
Application of 4D Seismic for Reservoir Management in Carbonates. Does it Work?
Authors: Saleh Efnik Mohamed , Haj Taib Samsudin
Published: July 2011

In the past ten years, time-lapse (4D) seismic has evolved from an academic research topic to a standard way of monitoring reservoir performance. The method is now being used as good reservoir management practice to provide evidence of saturation changes within the reservoir at field scale. 4D provides a new piece of data describing the dynamic behavior of the reservoir fluids between the wells, often limited to small scale monitoring at the borehole scale. Thus, it provides sophisticated techniques of reservoir monitoring and management relying on the integration of geological models, static and dynamic properties of the reservoir rock, and detailed production and pressure field data.

While 4D seismic data has been very successful in monitoring hydrocarbon production in clastic reservoirs, there is still no consensus on its applicability to carbonate fields. The main difficulty is the well-known fact that the acoustic velocities of carbonates are insensitive to saturation and pressure changes, relative to the clastics. Beside the geological processes such as production induced compaction which has large impact on porosity, density and permeability variation during the life of a 4D surveys, the complexity and heterogeneity of carbonate pore geometry and network further aggravate the difficulty of 4D applications. Although the geological characteristics may not change at small time scales but they are linked to fluid flow and distribution in the reservoir.

An Integrated approach of 4D seismic analysis using all historical production data along with open/cased hole logs and simulation models has demonstrated its viability to understand saturation changes in heterogeneous reservoirs. Thus using this approach as reservoir management tool to improve sweep efficiency and enhance field development plans.
An Integrated Approach to Monitor Gas Sweep in Heterogeneous Reservoirs
Authors: Saleh Efnik Mohamed , Haj Taib Samsudin
Published: July 2011

A zero offset VSP survey was acquired over a thick carbonate interval. The objectives of the repeat survey were to assess repeatability of the measurement, robustness of the time lapse VSP processing mainly to account for time lapse noise and quantification of the time lapse signal in the reservoir due replacement of water by gas caused by gas injection that occurred between the baseline and repeat surveys.

A long side of the two VSP’s, an array sonic (SDT) and the sonic scanner tools were run. The SDT was run to recover the monopole compresssional and shear waves, while sonic scanner to acquire both the dipole and monopole shear and compressional.

Data processing was focused on isolating the time lapse signal in the reservoir section by comparing the baseline and repeat VSP surveys and sonic logs. Both the baseline and repeat surveys were processed with identical parameters to ensure that the datasets are comparable at every processing step. The processed data shows a good degree of repeatability, and deterministic deconvolution as expected was enough to take care of source wavelet variations between the two surveys.

The time lapse VSP and sonic logs were run in carbonate reservoirs where gas is being injected to assess the effectiveness of recovering more oil as part of Enhanced Oil Recovery (EOR). The current recovery mechanism in the reservoirs is to inject water to enhance pressure support. The gas pilot objective is to increase the recovery factor to recover more oil and enhance productivity.
An Enhanced Oil Recovery Technology Continually after Polymer-Flooding
Authors: He Liu , Guo Li
Published: July 2011

There is no economical exploitation value when water cut of oil wells reaches 98% during the process of water flooding after polymer flooding. But the injection and production systems are still in good condition. Core data shows that there are about 21.2% remaining oil which mainly exists in low permeability zone. There are a great mount of residual polymer in place after polymer flooding. According to data analysis, there is 72.3% residual polymer left in the central well block in Bei-1-Duanxi. Water fingering that caused by mobility ratio differential and formation heterogeneity in subsequent water flooding reduces the sweep volume greatly. How to take charge of the residual polymer to conquer water breakthrough and enhance oil recovery after polymer flooding gives us a great challenge.
A Novel Method of Optimizing the Moelcular Weight of Polymer Flooding
Authors: Zhang Xiaoqin , Pan Feng , Guan Wenting , Li Dan , Li Xia , Guo Songlin
Published: July 2011

ABSTRACT The molecular weight of polymer is important to the efficiency of polymer flooding. Polymer solutions with higher molecular weight have better absorption, better capitation, higher resistance and residual resistance coefficients. All these imply higher recovery factor. But for reserviors of middle and low permeability, higher injected molecular weight means more unswept pore volume, lower controlling degree and recovery factor. Therefore, both higher injected molecular weight and controlling degree must be fully considered, so as to obtain a higher recovery factor in a given block. On the basis of lab experiments and numerical simulations, two matching charts are formed. One is about the relationship between molecular weight and layers and the other is about controlling degree on recovery rate. They are used to optimize the molecular weight for polymer flooding. This new method is applied in the project for polymer flooding in secondary layers of Daqing oilfield and an enhanced recovery factor of more than 8% is obtained. INTRODUCTION In polymer flooding, the solution viscosity is enhanced and water phase permeability is reduced. Sweeping volume is enlarged to increase recovery factor. Polymer molecular weight is the main factor in polymer flooding. Higher molecular weight means lower water phase permeability and higher recovery rate. However, in the industrialization of polymer flooding in Daqing Oilfield, it is indicated molecular weight should be optimized in accordance with permeability. Ultrahigh molecular weight needs high injection pressure and causes blocks in the layers, which leads to poor development. To the question, a new method is put forward to optimize the molecular weight.
Comprehensive Study to Determine Optimum Solvent Composition for VAPEX in a Heavy Oil Reservoir
Authors: Hosseinipour Abdolkarim , Azin Reza , Yunan Mat Hussin
Published: July 2011

Optimum solvent composition is a vital decision in ensuring the economic viability of the VAPEX process. The ideal optimum is dictated by reservoir characteristics such as temperature, pressure and bitumen properties. Condensation can be prevented through the addition of a non-condensable gas and if the partial pressure of the solvent mixture remains lower than the vapor pressure at reservoir temperature. In this work, different solvent mixtures were examined to investigate the performance of VAPEX process in heavy oil recovery in an Iranian reservoir. The optimum solvent composition was found through the comprehensive simulation work. Effects of injection rate and diffusion coefficient were tested. Optimum solvent composition for all cases was found as mixture of C1/C3 with 55/45 molar ratio. Results indicate that the recovery factor, the oil production rate and the cumulative oil production will be higher for solvent mixtures with diffusivity coefficient compare to solvent mixtures without diffusivity coefficient as well for optimum solvent. Effect of diffusivity on process is acknowledged well by peclet dimensionless number and this shows that at low injection rate, effect of diffusivity is more than displacement.
Crosswell Technologies: New Solutions for Enhanced Reservoir Surveillance
Authors: Marion Bruce , Safdar Muhammad , Wilt Michael , Zhang Ping , Loh Fabian , Nalonnil Ajay
Published: July 2011

Resolution and measurement diversity are important parameters that help characterize the subsurface and help optimize reservoir management. While traditional well log data provide a variety of high-resolution measurements of the formation very close to the wellbore, surface-based methods provide larger investigation volume but coarser resolution. Crosswell measurements help to bridge the gap by imaging the inter-well space at reservoir scale.

Crosswell seismic data provide high resolution reflection images of reservoir architecture with resolution that is up to 10 times better than that of surface seismic data. Crosswell Electromagnetics (EM) expands the scale investigated by tradition al resistivity logging to deliver, a more extensive understanding of fluid distribution and movement at reservoir scale, away from the wells. Not only do these techniques complement each other, but integrating the measured data with conventional logs and surface data into the modeling workflow gives new insight into reservoir structure and fluid movement in the formation.

Recent surveys in various improved recovery projects show that these complementary measurements provide a new way to help subsurface teams accurately image geology and map injection fronts.
Pilot Tests for Enriched-Gas Flooding with Small Well Distance at Zarzaitine Oil Field
Authors: Wang Sheng Kui , Li Min , Li Dao Xuan , Li Hai Long , Cheng Wei , Wu Xiu Li , Xiao Qian Yin
Published: July 2011

This presentation provides a technical overview of a project aimed at evaluating the feasibility of Enriched-gas injection by using a small well distance in the later period of the pilot tests. The advantage of a small well distance is that the initial and peak production responses can be reached early. Thus, the feasibility evaluation could be initiated sooner. Pilot tests in two areas were conducted. The first pilot test was performed by continuous gas injection in area IA with well distance 250 meters. The purpose of this test was to evaluate the effect of the continuous enriched-gas injection on the relative high permeability layer IV. The second pilot test was carried out in area IV using WAG process with well distance 150 meters. The goal was to see if WAG can enhance oil recovery by injecting into and producing from layers II, III, and IV simultaneously. The implementation for IA area was stopped due to solvent breakthrough after 112 days of operation. The oil recovery was increased by 8.9% compared with water flooding. The other pilot test in IV area is still in operation. A numerical simulator has been used to predict the oil recovery after matching production performance. The oil recovery is significantly lower than that in IA area because of faulty perforations in the main producing layer IV. However, compared with water flooding, an encouraging increment by 5.39% can be obtained by deducting layer IV’s OOIP. These results show that both continuous injection and WAG process can improve oil recovery significantly. The numerical simulation study showed that a large well distance can also increase oil recovery in both of the testing areas. Further tests with the wells at larger distance may be performed in the future.
Field Experience of Produced Polymer Control in Offshore Oilfield
Authors: Xiang Wentao , Zhou Wei
Published: July 2011

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

After 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

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.