bluuebunny/crossref_metadata_2025_split huggingface dataset:
Design, Operation, and Laboratory Work for Single-Well Tracer Test Campaign in Handil Field Indonesia
Authors: Mechergui A.. , Agenet N.. , Romero C.. , Nguyen M.. , Batias J.. 
Published: July 2013

Abstract
This paper focuses on the design, the operation and the laboratory work needed for performing a successfull Single Well Tracer Test (SWTT) campaign in the Handil mature field Indonesia. Three tests have been performed in different waterflooded reservoirs to assess the repartition of Remaining Oil Saturation (ROS) in the field.
An extensive laboratory work has been performed prior to tests to screen chemicals that could be used and then to measure the two main parameters needed for the design of the tests: the partitioning coefficient of the primary tracer between water and oil (Kd) and the hydrolysis reaction rate (kH) of the primary tracer into the water. Measurements were performed at reservoir temperature and pressure conditions using recombined live oil sample and recombined brine with respect to the salinity of each reservoir. Results indicate very low discrepancy of Kd value between reservoirs (4 to 5), while kH show a strong linear dependency with salinity (from 0.12 to 0.45 day−1). To take into account the presence of trapped gas saturation, we measured also the partitioning coefficient of AcOET between the water and the gas phase at reservoir pressure and temperature. As expected the Kd water/gas was low compare to the water/oil with a value of 0.5.
Tests were performed in parallel after the installation and the calibration of laboratory equipments and the commissionning of the injection barge. The tracer profiles quality recorded from the three tests was very good with high tracer recovery and low scattering data. However the interpretation was challenging, and numerical simulation was necessary to handle non ideal phenomenan occurring during these tests and to get reliable ROS estimation. The ROS values range between 20-30% which allows moving forward in the identification of potential EOR reservoir candidates and locations of future pilot zones for the more promising EOR processes.
Case History: Monitoring Gas (CO2) Flood in a Carbonate Reservoir with a New Slim Multidetector Pulsed Neutron Tool
Authors: Kwong Kwokshan , Liu Zhipeng , Guo Weijun , Jacobson Larry 
Published: July 2013

Abstract
In mature fields, optimization of CO2 flood and tertiary oil recovery demand accurate and consistent formation evaluation in producing wells. The complex well history—including near-wellbore (NWB) stimulation and recompletion for flood injection—often poses challenges to interpretation. Conventional water saturation (Sw) from resistivity based saturation modeling is of large uncertainty because of reservoir heterogeneity: variable M, N, and Rw parameters. Often, openhole (OH) logs might not even be available.
To address these challenges, a new multidetector pulsed-neutron tool (MDPNT) has been designed to enhance radial measurement sensitivity. In this paper, case histories are examined to illustrate a consistent workflow for deriving calibrated cased-hole (CH) porosity from capture gamma ratios and gas saturation from gas saturation gate (SATG) response of the MDPNT. The SATG curve computed as the ratio between inelastic counts and slow capture counts from a single gamma detector has reduced lithology and water salinity dependences compared to traditional saturation analysis using a PNT.
CH MDPNT accurately identify CO2 breakthrough and monitor CO2 saturation changes. Time lapse use of MDPNT and log interpretation guides conformance work design to improve aerial and vertical sweep efficiency in the field.
EOR Strategies for a Conventional Heavy Oil Reservoir with Large Aquifer in Greater Fula Oilfield, Sudan
Authors: Wu Yongbin , Li Xiuluan , Liu Shangqi , Ma Desheng , Jiang Youwei 
Published: July 2013

Abstract
Thermal recovery technology particularly cyclic steam stimulation (CSS) is always an effective means to develop the conventional heavy oil reservoirs, which can be validated from literature. While most of the heavy oil reservoirs developed by CSS are the thick, well-deposited, high quality reservoirs and there are no much reports of producing oil from mid-depth oil reservoirs with large acquifers.
In this paper, according to the petrophysical properties and geologic characteristics of the target block F in Greater Fuld oilfield in Sudan, based on the oil test results, detailed 3D geologic model is established and the type well model for CSS and SF is extracted, to study the real performance with the real geological properties.
The development zone, the perforation strategies, the cylic steam injection quantity, the steam injection rate, soak time, and cyclic period are optimized for CSS. Based on the production performance of CSS, the optimal cycles of CSS followed by SF is determined. And the wellpattern and well spacing, the parameters of SF such as unit steam injection rate, steam quality, effects of bottom acquifer on the SF are also simulated and optimized. The simulation results indicate that the thermal recovery technique especially 4 cycles of CSS followed by SF can acquire satisfied performance, which shows an effective and economic future in the development of the heavy oil deposits in Greater Fula Oilfield.
Optimization of Gas Utilization to Improve Recovery at Hibernia
Authors: Lawrence J. J. , Sahoo Hemant , Teletzke Gary F. , Banfield Jessica , Long Jamie M. , Maccallum Nicholas , Noseworthy Ryan J. , James Lesley A. 
Published: July 2013

Abstract
The Hibernia oil field is located in the North Atlantic Ocean over 300 km from St. John's, Newfoundland. The field consists of numerous fault blocks undergoing conventional gas or water injection. The gas injection process is proving to be very efficient providing high recoveries in individual blocks. Expansion of gas injection through conventional development or EOR may potentially provide significant benefits if optimized correctly under a limited gas supply. The need to understand the relative benefits of gas injection into one block versus another has increased and necessitated a full gas utilization study. One EOR option being considered is water-alternating-gas (WAG) injection in some blocks.
The objective of the study is to establish a field-wide improved recovery plan based on integrated laboratory, reservoir simulation, pilot, gas supply, and infrastructure studies. This paper will describe the integrated study plan and current progress.
The Gas Utilization Optimization Project entails three broad phases: 1) Study Phase; 2) WAG Pilot Execution; and 3) Field-Wide EOR Development. The primary focus at this point is the Study Phase, which will include laboratory studies, reservoir simulation studies, pilot engineering studies, and gas supply and infrastructure assessment.
The laboratory studies are being performed to develop a better understanding of PVT, EOR, and SCAL as it applies to the WAG pilot and field-wide development. The reservoir simulation studies provide a basis for the design of the EOR pilot and the field-wide development plan. Pilot engineering must be performed to ensure the pilot will provide the information necessary to make business decisions on future development. Assessing gas supply and infrastructure is essential to understanding gas availability, value, and opportunities for enhancement. This phase is particularly important for remote locations where external gas supplies are limited.
This study provides a template for obtaining and integrating information and data necessary to design, evaluate, and implement a gas injection project for improved oil recovery.
Developing and Piloting Water Treatment Technologies to Address Offshore EOR Challenges
Authors: Henthorne Lisa , Martin Chris , Johnson Holly 
Published: July 2013

Abstract
Water-based Enhanced Oil Recovery (EOR) technologies such as Low Salinity Flooding (LSF), Chemical EOR (CEOR), and steam-flooding have been growing in popularity over the years, and are generating new opportunities for the water treatment sector as a result. Water treatment technologies have the unique capability to address equipment and system requirements which are characteristic of EOR projects. However, these technologies typically have little to no history of application in the upstream oil and gas industry. This limited level of experience may impact EOR project budgets and schedules, particularly in offshore applications where weight and footprint availability are of critical value.
In Southeast Asia, two offshore projects are investigating the use of customized water to maximize oil recovery in CEOR applications. In the first project, two CEOR programs consisting of vastly different water quality cocktails are under consideration, one of which incorporates produced water into its water source. In the second project, injection water quality with an ultra-low hardness level is desired, in order to prevent potential precipitation in the reservoir. In both cases, water treatment infrastructure must be capable not only of producing the intended injection water quality, but it must do so consistently in response to potential changes in the quality of the source water used.
This paper describes the results of pilot testing of two typical water treatment technologies, Reverse Osmosis (RO) and unique nanofiltration membranes, to produce a variety of injection water chemistries for CEOR and LSF applications. These applications include ultra-low hardness, high salinity; and low hardness, low salinity injection water. The testing confirms the ability of new water treatment technologies to solve challenging issues that arise in EOR applications, particularly those in offshore applications that must respond to varying needs of reservoirs and footprint/weight limitations.
Integration of Geological & Coupled 3D Geomechanical Modelling to Evaluate Gas Injection Risk - A Due-Diligence Study Prior to iWAG Injection Development for the Bokor Field, Offshore Malaysia
Authors: Press D. J. , Pang C. M. , Meyer J.. , Roh C. H. 
Published: July 2013

Abstract
As part of the development planning of an alternating water and gas injection scheme for Enchance Oil Recovery in the Bokor Field, a risk evaluation study was carried out to assess the likelihood of injection gas migration from the reservoir to the seabed. This hazard was identified as a principal HSE risk to the platform installations by the Bokor Field development team. A work flow was constructed which involved the integration of geological and petrophysical based seal evaluations with coupled fluid-stress geomechanical modeling of the depletion and injection processes over the life of the field to determine reservoir shale seal efficiency and gas leakage risks due to both hydraulic fracturing and fault reactivation. The coupled geomechanical modeling process incorporated, not only the resulting pressure changes arising due to depletion and injection within the reservoir, but also utilized a consolidation scheme to model the imposed pore pressure changes within the overburden arising due to stress transfer, and the subsequent dissipation of these excess pore pressures with time.
Evidence of fault related gas migration in the geological past is seen by the presence of a shallow gas cloud identified on seismic data sitting above the crest of the structure. The scope of the study included the evaluation of this cloud on various vintages of seismic from 1976 to 2011 to determine whether the size and geometry of the gas cloud was related to previous field development.
The study clearly demonstrates the application of coupled geomechanical modeling in assessing surface and subsurface risks resulting from field development.
A New Computational Model to Predict Ternary Phase Behaviour of Brine/Oil/Surfactant Mixtures for Chemical Enhanced Oil Recovery CEOR Methods
Authors: Adeeyo Yisa A. , Awang Mariyamni B. , El-Khatib Noaman 
Published: July 2013

Abstract
Surfactant flooding is an enhanced oil recovery process used to mobilize the residual oil by lowering the interfacial tension (IFT) between oil and water. When surfactants are mixed with brine and oil, oil in water, water in oil microemulsions could be formed with region of ultra low IFT. The ability to predict the number of phases formed, their relative amount, and compositions at a particular reservoir brine concentration is crucial for successful CEOR planning.
Equations of state (EOS) such as the Peng-Robinson (PR) and Soave-Redlich-Kwong (SRK) are usually used to predict the phase equilibrium. They require critical properties and accentric factors of the components. However, since oil and surfactants are not pure substances, they are treated as pseudo-components for which the pseudo critical properties must be estimated. Also, PR and SRK EOS are originally developed for non-ionic, non-polar and non-associating hydrocarbons. These pose some limitations in their application to surfactant/Brine/Oil mixture.
This study presents a new computational model to estimate surfactant/brine/oil ternary phase behaviour using PR EOS. In this study we have adopted group contribution model (GCM) using information from the molecular structure of the pseudo components for the estimation of their critical properties. A numerical solution is developed for solving the system of nonlinear equations governing the phase equilibrium by means of Newton-Raphson iterative procedure.
Phase behavior experiments were conducted at temperature of 50°C using Alfa Olefin Sulfonate (AOS) surfactant, decane and brine. Brine concentrations were varied at each temperature and phase relative amount and compositions were determined. The laboratory results were compared with the results predicted by the model. The study shows the level of reliability of our new predictive model. The model developed can be used in compositional simulation of surfactant flooding operations and should prove to be an invaluable tool in planning and evaluation of surfactant flooding processes.
Chemical EOR: Challenges for Full Field Simulation
Authors: Shaharudin M. Shahid , Jalan Shlok , Masoudi R.. , Othman M. B. 
Published: July 2013

Abstract
Chemical EOR projects were very active during 1980's, however, during 90's the interest in chemical EOR has fallen due to the low oil prices and also technical challenges that the methods poses. While surfactant flooding has difficult design considerations of chemicals, large capital requirements and is very sensitive to local reservoir heterogeneities, alkali can react strongly with minerals in the connate water and reservoir rocks may adversely impact the process. This complex process is yet to be understood. If the field is offshore, chemical EOR becomes even more challenging due to sophisticated logistics, incremental costs, highly deviated wells, larger well spacing and limited well slots on the platform. However, recently there has been a renewed interest in chemical flooding mainly due to valuable insights gained through chemical floods done in the past and better technical understanding of the processes and favorable economic conditions.
For robust production forecasts, various uncertainties due to complex chemical processes should be quantified thoroughly. Some of the important uncertainties for full field production forecasts are chemical adsorption on rock surface, interfacial tension (IFT) and residual oil saturation reduction by chemical. Proper coreflood experiments are critical to reduce these uncertainties. Careful matching of coreflood experiments in numerical simulations is also important which provides key inputs for full field forecast. Another important element in the successful commercial application for chemical EOR process is a well-designed pilot. After the completion of pilot, the results should be carefully matched in the simulation model. Once satisfactory match is obtained, the key step would be to upscale the results to the full field level.
Discussed in this paper are the impact of some of these uncertainties and the method used to reduce them. In this paper the workflow and key tasks in dealing with the simulation of chemical EOR process elements like residual oil saturation, IFT reduction and adsorption parameters are discussed. The results show that the incremental oil is very sensitive to the various simulation inputs.
Inline Viscosity Monitoring of Polymer Solutions Injected in Chemical Enhanced Oil Recovery Processes
Authors: Bonnier J.. , Rivas C.. , Gathier F.. , Quillien B.. , Thomas A.. 
Published: July 2013

Abstract
The development of chemical enhanced oil recovery projects throughout the world is on a fast pace, led by a will to increase the final recovery of mature and newly developed hydrocarbon reservoirs The validation of the process is usually achieved by implementing an injection pilot; the goal is to understand, secure, and optimize the technology and to assess its efficiency on increasing final oil recovery for carefully determined capital and operational expenditures.
One of the key factors for a successful polymer flood is the polymer solution viscosity that must remain on target during the transport from its initial preparation, to the well head and down to the reservoir. Thus, a reliable method is required to measure and monitor the polymer solution viscosity on different points along the dissolution, dilution, mixing, and injection lines. This method must take into account the polymer solution characteristics among which the non-Newtonian behavior and sensitivity to mechanical and chemical degradations.
This paper presents recent developments of a specific in-line viscometer, which can measure the viscosity at low shear-rate, as per real reservoir conditions, with pressures ranging up to 250 barg. The equipment consists in a low flow, non-shearing pump, which circulates the solution through a given tube (length and diameter) where the pressure drop is measured and allows low-shear viscosity to be extrapolated. Calibration methods and first results are presented in this paper to illustrate the accuracy of the technology and potential installation benefits for chemical enhanced oil recovery operations. The viscometer is made of highly resistant material and can be implemented in all hazardous areas in remote mode without manual operations, no waste and very little maintenance.
This new device has been designed to solve the common issues encountered with the vast majority of commercial equipment that is not compatible with currently injected polyacrylamide solutions. It will also allow operators to gather reliable data compared to manual sampling methods that, in addition to requiring manpower, are not easy to conduct without degrading the polymer solutions.
Recovery of Oil from High Salinity Reservoir Using Chemical Flooding: From Laboratory to Field Tests
Authors: Shiau Ben , Hsu Tzu-Ping , Lohateeraparp Prapas , Rojas Mario , Budhathoki Mahesh , Raj Ajay , Wan Wei , Bang Sangho , Harwell Jeffrey H. 
Published: July 2013

Abstract
Reservoirs containing very high total dissolved solids and high hardness make the design of a surfactant polymer (SP) flood extremely difficult because surfactant tends to precipitate and separate under these conditions. Beside divalent ions, Ca2+, Mg2+, presence of iron in the brine can be a challenging issue. Different surfactant formulations are evaluated and incorporate cosurfactants and co-solvents which minimize viscous macroemulsions, promote rapid coalescence under Winsor Type III conditions, and stabilize the chemical solution by reducing precipitation and phase separation. The optimal surfactant formulations were further evaluated in one-dimensional sand packs and coreflood tests using Berea sandstone, reservoir oils, and brines at reservoir temperatures. Using similar injection protocols, 3 pore volumes of surfactant-only system, experimental results show the oil recovery ranging from 45 % to 70% of the residual oil (Sor) after water flooding. The level of surfactant loading is less than 0.5 wt%. A single-well test was conducted to confirm laboratory results in situ in the presence of high-salinity formation water containing 102,300 mg/L total dissolved solids (TDS). The aim of ongoing test is to confirm the effectiveness of the high-salinity surfactant-only formulation (0.46 wt% of surfactant). In this effort, we plan to conduct multiple single-well tests at different wells to minimize the design risks involved for the surfactant pilot test. A pilot test at a sandstone reservoir is scheduled to be performed in July of 2013 to further evaluate the effectiveness of surfactant formulation and address technical issues related to scale-up.
The Successful Implementation of a Novel Polymer EOR Pilot in the Low Permeability Windalia Field
Authors: Haynes Andrew K. , Clough Martyn D. , Fletcher Alistair J. , Weston Stuart 
Published: July 2013

Abstract
Barrow Island's Windalia reservoir is Australia's largest onshore waterflooding operation and has been under active waterflood since 1967. The highly heterogeneous reservoir consists of fine-grained, bioturbated argillaceous sandstone that is high in glauconite clay. The high clay content results in a low average permeability (5 md) despite high porosities (25-30%) and hence fracture stimulation is required to achieve economic production rates.
The Windalia reservoir and fluid properties preclude the use of traditional EOR technology, with thermal, miscible and mobility control processes all deemed unfeasible through screening studies. Consequently, the in-depth flow diversion mechanism was developed and applied, which utilizes a low molecular weight polymer to drive the growth of induced hydraulic fractures in the treated injection wells. A 3-injector pilot was executed involving polymer injection for two years, with no detrimental injectivity losses observed for polymer concentrations up to 750 ppm. Considerable fracture growth, oil production rate uplift and reduction in water cut were observed throughout the pilot pattern, in line with predictions: Fracture half-lengths increased from 6 ft to 400 ft in one injector and from 141 ft to 322 ft in anotherAn initial oil rate uplift of 38% relative to the production baseline was observed; a more conservative estimate suggested that at least half of this was attributable to the tertiary recovery processThe water-oil ratio was observed to fall from 15 to 11, similarly timed with the oil production increase.
These improvements were observed consistently throughout the pilot area and were distinct from the waterflood behavior elsewhere in the field. This paper briefly summarizes the technology screening and pilot execution stages, after which the results from the pilot are presented and discussed. This technology may be of use in other low-permeability waterfloods with induced injector fractures, for which traditional EOR practices are believed to be unfeasible.