bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

AbstractWater 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

Abstract
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

Abstract
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

Abstract
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.
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

AbstractOptimum 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

Abstract
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

Abstract
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.