bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Comprehensive EOR Study Using Low Salinity Water in Sandstone Reservoirs
Authors: Alotaibi M. B. , Azmy R. M. , Nasr-El-Din H. A. 
Published: July 2010

AbstractIt has been reported that the ionic strength of injection water can have a major impact on the recovery of hydrocarbons during waterfloods, with increased recovery resulting from the use of low salinity brines. Understanding how the water and oil chemistry affects the final recovery from a physicochemical point of view is necessary in order to optimize low salinity water flooding process. It is clear from the literature over the last two decades that wettability is considered a key factor in achieving the low salinity effect. Optimum ionic strength and conditions for low salinity flood with respect to wettability is still uncertain.In this study, we integrate new coreflood apparatus using core samples, up to 20 inch length, to mimic and understand crude oil/water/rock interactions. The coreflood experiments are conducted under both secondary and tertiary recovery modes. We applied contact angle method to study rocks wettability. Reservoir rocks and stock-tank crude oil sample (west Texas) are utilized in all experiments. Synthetic brines varying in salinity (up to 174kppm) are tested under elevated temperature and pressure conditions. As ion exchange plays a crucial role in changing wettability, chemical analyses are performed on the effluent samples. Moreover, Zeta potential is determined for sandstone rocks and selected clays as a function of ionic strength.Residual oil saturation is determined with all variation in wettability, brine salinity, and temperature conditions. Some core flood tests give an incremental increase in produced oil as decreasing the injection brines ionic strength. Experimental results indicate that adjusting brine salinity may enhance oil recovery under certain conditions. This paper gives a new insight into optimum salinity and provides better understanding of interaction between injected brine, the oil, and the rock at downhole conditions.
Field Applications of Behind-Pipe Saturation Evaluation in a Miscible CO2 Flood
Authors: Hughes R. G. , Amadi S. U. , D'souza D. F. 
Published: July 2010

Abstract
To evaluate the amount of bypassed oil in a CO2 flood, it is necessary to obtain some estimate of the remaining oil saturation. Near wellbore oil saturation determination requires a tool or sequence of tools that is able to distinguish oil from other phases that may be present in situ especially when those phases are miscible with the oil. Cased hole logging in waterfloods, steam floods and CO2 sequestration cases has been presented and the techniques used are in the process of becoming reasonably reliable evaluation tools. Very little work has been presented on the case where an existing CO2 flood needs to be evaluated, but has no baseline cased hole logs to tie to.
This paper presents the results of field tests where carbon-oxygen and pulsed neutron logs were used in combination to evaluate in situ saturations in an area where oil, water and CO2 are present but where no previous (baseline) cased hole logs had been run. One of the wells had a nearby core characterization and modern open-hole logs to tie the cased hole logs to while another was in the same formation, but only had 1960's vintage open-hole logs. Techniques described in a previous publication were used to perform the evaluation.
The theoretical result previously presented worked fairly closely to what was described. However, there are a number of variable parameters required that need to be evaluated and reasonable estimates (or methods to obtain reasonable estimates) of those values are not well documented. This paper will also document the methodologies that seemed to work to successfully estimate these parameters.
The Role of Co-Solvents and Co-Surfactants in Making Chemical Floods Robust
Authors: Sahni Vinay , Dean Robert M. , Britton Chris , Kim Do Hoon , Weerasooriya Upali , Pope Gary A. 
Published: July 2010

Abstract
The ability to select low-cost, high-performance surfactants for a wide range of crude oils and reservoir conditions has improved dramatically. There are thousands of possible combinations of chemicals and components (including differing salinities, hardness, and oil concentrations) that could be tested on each crude oil. Each chemical combination requires many observations at reservoir temperature for proper evaluation. Therefore it would take too long, be too expensive, and in many cases not even be feasible to test all combinations. In practice we use our scientific understanding of surfactant/co-surfactant/co-solvent characteristics to match a chemical formulation to the properties of a crude oil and formation brine salinity at reservoir temperature. Typically the surfactant is mixed with other chemicals such as polymer in brine and injected at optimum salinity (the ASP slug). It is important that the ASP slug be a clear, stable solution since precipitation or phase separation will interfere with surfactant and polymer transport deep into the reservoir. Co-solvents and/or co-surfactants are often needed to make the primary surfactant sufficiently soluble. Core floods are presented that show the oil recovery is significantly increased by simply adding a small concentration of co-surfactant to make the ASP slug clear. In such cases, the use co-solvent/ co-surfactant is economically beneficial in terms of higher oil recovery because of the improved surfactant performance, lower surfactant retention and improved effectiveness of the polymer for mobility control.
Alkaline - Surfactant - Polymer Flood (ASP): Single Well Chemical Tracer Tests - Design, Implementation and Performance
Authors: Oyemade S. N. , Al Harthy S. A. , Jaspers H. F. , Van Wunnik J , de Kruijf A. , Stoll M. 
Published: July 2010

Abstract
Studies in a number of mature fields in Oman have shown that alkaline surfactant polymer (ASP) flooding can potentially yield significant incremental recoveries with respect to water flooding. The technique however, is still immature especially in PDO as reflected in the number of key risks that have been identified; (i) poor injectivity of the ASP slug, (ii) effectiveness of reservoir sweep, (iii) formation of scale in the wells and facilities and (iv) persistent emulsions in the produced fluids. Analysis of these risks has highlighted the need for piloting before full field implementation.
Two stages of piloting have been considered, Single Well Chemical Tracer (SWCT) test and Continuous Injection Pilot (CIP). This paper covers the SWCT trials with focus on design and implementation challenges and finally discusses performance and results.
A total of five wells were selected for the trial in three different fields across Oman to capture different reservoir settings. The ASP SWCT tests aim to confirm the suitability of the ASP process, the potential recovery factor increase and mitigate some key risks, mainly injectivity and sweep. The trials are designed to evaluate the remaining oil saturation before and after injection of ASP cocktails to determine incremental oil recovery.
Various challenges were faced in planning the project. Completion challenges due to age of existing wells / casing, well shape, type of artificial lift, need to produce / inject water and ASP cocktail from same wells. Water source / tie-in for preliminary flooding also varied in each field. Handling of produced fluids during tests required special attention to avoid destabilizing the production station. Treatment sequence, equipment layout and logistic requirements were different for each field. Procedures were developed for each field incorporating chemical preparation and mixing. Overall, Project Management and good interface were critical to successful implementation of the tests, the first in PDO.
Fracturing Design Aimed at Enhancing Fracture Complexity
Authors: Soliman M. Y. , East Loyd , Augustine Jody 
Published: July 2010

Abstract
The potential for shale formations as a source of gas production has been recognized. However, shale permeability in a nano-Darcy scale represents a significant technological challenge to recover trapped hydrocarbon effectively. The fracturing of wells has been widely used to enhance the economic aspects of the reservoir. Connecting the created hydraulic fractures to the natural fractures or induced-stress fractures would further improve the productivity of the wells. Fracturing heterogeneous (naturally fractured) formation involves unique aspects in the fracturing processes, rock mechanics, and fluid-flow aspects.
In some cases, the natural fractures might not be sufficiently conductive or could be held closed during fracturing operations as a result of the existing in-situ stresses. In this paper, hydraulic fracturing-design techniques to neutralize the stress anisotropy in the formation to allow the opening of the natural fractures during the hydraulic-fracture propagation are presented. Overcoming anisotropy effects would allow the operator to inject moderate amounts of proppant into the natural fractures and maximize the contact area within the reservoir.
Geomechanics development behind these techniques is presented in this paper. The presented technology would allow operators to optimize placement of fractures across the horizontal well based on the geomechanics properties of the formation. The fluid-flow aspects of these enhanced completion processes are also discussed.
Interfacial Stability and Displacement Efficiency in Thermal Solvent Processes
Authors: Sharma Jyotsna , Gates Ian D. 
Published: July 2010

Abstract
Expanding-Solvent Steam-Assisted Gravity Drainage (ES-SAGD) and Solvent-Assisted Cyclic Steam Stimulation (SA-CSS) are in situ steam-solvent recovery process to produce heavy oil and bitumen reservoirs. In ES-SAGD and SA-CSS, steam and solvent are injected into the depletion chamber within the reservoir. At the chamber edge, the steam releases its latent heat heating the oil there and solvent mixes with mobilized bitumen which then flows under gravity to the lower horizontal producer. There are many factors that influence the efficiency and rate at which oil is mobilized. One of them is the stability of the steam-oil interface which is controlled by the concentration and temperature dependencies of viscosity and density and the relative magnitudes of viscous, gravity (buoyancy), and capillary forces. In this research, the stability of the chamber interface between the vapour chamber and the bitumen at the edge of the chamber is examined. We present theoretical evidence for occurrence of such instability and conditions at which the interface is unstable. The results demonstrate that steam-solvent injection enhances the instability of the interface thus promoting greater mixing at the edge of the chamber. Consequently, the oil rate of a steam-solvent process is higher than that of a steam-only one. Therefore, there are three fundamental contributions to enhanced production by solvent-steam processes: first, the oil phase viscosity is lowered, second, the oil saturation is enhanced at the edge of the chamber, and third, the vapour-oil interface becomes more unstable which promotes more mixing at the chamber edge. The stability of the interface is also controlled by the balance between the solvent's solubility in the oil phase and the ability of the solvent to reduce the viscosity of the oil phase. The results of the stability analysis confirm the findings of laboratory experiments and field tests which demonstrate that processes that use solvent+steam yield higher production rates than that of steam alone.
Valhall – Pushing the Limits for Openhole Zonal Isolation — Qualification and Field Trial of 10,000-psi Oil-Swelling Packers
Authors: Nijhof Jeroen , Koløy Tom Rune , Andersen Kristian 
Published: July 2010

Abstract
The paper outlines the full-scale qualification testing of high differential pressure (ΔP) swellable element packers (SEPs) for fracture stimulation application in prop fracture stimulation in production wells on the Valhall Field, which is operated by BP Norge AS.
The SEPs use solids-laden oil-based mud (OBM) to expand the element installed on the outer surface of the basepipe, which forms part of the reservoir liner. This eliminates the need to spot dedicated swelling fluid.
Also discussed is the system used to perform the fracture stimulation in the field. The results of the successful qualification full scale testing up to 10k psi across two 5-meter packers are described. Details are also given for the Valhall Field operation with the deployment and swelling of 20 SEPs, followed by the hydraulic fracturing operation.
Reservoir management for the Valhall redevelopment program relies on multi-zone water injection and proactive management of unwanted water production. Produced water isolation is achieved with an arrangement of heavy-duty sliding sleeve circulating devices. A method of annular zonal isolation to prevent flow behind the reservoir liner is essential to success.
The oil-swelling SEPs offer a viable alternative and several improvements over the currently used cement barriers. These advantages are described in the paper. At the heart of these is the key requirement that any annular barrier must withstand very high ΔP (10k psi) during stimulation of the individual producing zones.
Several unsuccessful attempts had been performed to qualify a SEP to 10k psi for Valhall; therefore, it was decided to try a new design featuring an innovative mechanical end-ring system. This represents a step change in the design methodology of SEPs. It enables reduction of element length and packer OD while retaining high differential pressure (DP) ratings and/or increase the DP rating of long SEPs. The features and benefits of the new SEP design are presented.
Evaluating the Effects of Well-Type Selection and Hydraulic-Fracture Design on Recovery for Various Reservoir Permeability using a Numeric Reservoir Simulator
Authors: Shelley Robert F. , Soliman M. Y. , Vennes Mike 
Published: July 2010

Abstract
The industry is faced with the task of producing hydrocarbon from increasingly tighter reservoir rock, including low-permeability sand and shale. As a consequence, the selection of an appropriate well type and fracture-stimulation design is becoming more critical to project success. The purpose of this paper is to provide some clarity by providing a general understanding about the effects of well-type selection and hydraulic-fracture design on hydrocarbon recovery for various reservoir-permeability scenarios. Well types modeled include vertical, stimulated vertical, horizontal, axial-stimulated horizontal, and transverse stimulated horizontal with variations in compartment length and effective fracture length. This information has proven useful in the evaluation and planning of moderate to low to ultralow-permeability well projects.
The summaries presented in this paper are a compilation of the results from numerous simulator runs for black oil, gas condensate, and gas cases. These simulator runs included sensitivities on well type and permeability to compare recovery and production. Important conclusions pertaining to the recovery of hydrocarbon from low-permeability reservoirs and shale are made. In addition to validating the obvious conclusion about the increasing difficulty in recovering hydrocarbons from lower-permeability rock, a primary conclusion is that, as reservoir permeability decreases, proper well-type selection and correct hydraulic-fracture-stimulation design becomes much more crucial. The conclusions also show that, for a given permeability, obtaining significant recovery of oil can be a much more difficult problem than with dry gas.
Enhanced Gas Recovery, Challenges Shown at the Example of three Gas Fields
Authors: Clemens Torsten , Secklehner Severin , Mantatzis Konstantinos , Jacobs Bas 
Published: July 2010

Abstract
CO2-EOR has been used successfully to recover incremental oil after water flooding. In the USA, more than 260,000 bbl/d are produced by using this EOR method. CO2 Enhanced Gas Recovery (CO2-EGR) has also been proposed, however, only small scale projects have been performed until know.
In this paper, the challenges of CO2-EGR are addressed at the example of three fields.
The Hoeflein Field (Austria) contains gas condensate with a maximum liquid drop out of 4 %. The simulation results show that CO2 injection can recover incremental condensate. However, owing to the shape of the reservoir, CO2 will break through early. Hence, gas recovery will be reduced compared with conventional gas production.
The second field which was investigated is located in Pakistan. This field is an elongated field. The production wells are distributed over the full length of the field. CO2 injection can increase recovery (0.2 % maximum) only, if the surface facilities are able to handle high CO2 contents in the produced gas (more than 50 %).
The Schoenkirchen Uebertief Field (Austria) is a deep (5700 mSS), elongated structure. The production wells are located at one end of the structure. To recover incremental gas, good well placement and gas injection later in the lifetime of the field is required, about 1.5 % additional gas compared with depletion drive can be expected.
The example cases of CO2-EGR show that even for almost ideal reservoir structures (elongated with wells at one end and injection at the other end), limited potential for CO2-EGR exists. To increase gas production compared with depletion, a good well placement and knowledge of the structure accordingly is required, the production facilities have to be able to handle high CO2 contents and CO2 injection should commence later in the life-time of the field to avoid trapping of hydrocarbon gas in unswept areas at high pressures.
Integrity Management of Hydrocarbon Riser Caisson System
Authors: Anunobi Kingsley 
Published: July 2010

Abstract
The major design consideration for the hydrocarbon caisson is to protect the risers against external impact from supply vessels, intervention vessels etc. It also protects the riser from hydrodynamic loading and corrosion but in contrary makes the inspection of the riser external and caisson internal wall difficult.
A hydrocarbon riser caisson represents a safety critical item of an offshore platform installation. The major threat of loss of riser caisson integrity cannot be over emphasised. Loss of containment could be as a result of corrosion of the riser external and the caisson internal if the caisson annulus is not well managed. The corrosion process will gradually reduce the wall thickness of the riser until failure resulting from pressure build-up of hydrocarbon within the caisson annulus. The likelihood of caisson failure is increased if the caisson itself has suffered from internal or external corrosion.
This paper will describe the processes involved in managing the integrity of riser caissons/j-tubes as highlighted by the failure of a gas lift riser located within a hydrocarbon caisson. A study of the associated riser Caissons is presented highlighting the basic approach taken for the integrity review/re-assessment of all the remaining hydrocarbon riser caisson facilities within the North Sea field complex. The integrity review process applied, involved the detailed review of the general arrangement of the system, the design intent, the current integrity management status and the integrity management requirements for the riser caissons.
A risk based inspection approach could then be used to generate an integrity management plan based on the current integrity management strategy developed. In this way further loss of hydrocarbon containment issues, with their associated risk and cost within the field complex, could be prevented.
Prevention Better Than Cure – Emulsion Prevention of SOBM With Heavy Brine & Frac Pack Fluid in a GoM Gas Well
Authors: McBee Jim , Singh Amit , Arceneaux C. , Berry S. 
Published: July 2010

Abstract
A gas well in GoM was drilled with Synthetic Oil-Based Mud (SOBM) to achieve acceptable completion efficiency. During the drilling phase more than 4,200 bbl of SOBM was lost to the pay zones. Wells within near proximity, drilled with SOBM in similar reservoirs had a history of emulsion problems with SOBM, heavy-density completion brines and frac pack fluids. Those wells experienced productivity issues related to high drawdowns due to emulsions that were visibly produced to surface. Remedial treatments were necessary to produce these wells effectively. The results after remedial treatments were effective, but did not maximize production to its full potential. Hence, prevention rather than remedial treatments of the emulsion was desired during planning of the new completion.
This paper examines the completion of a gas well, where efforts were made to prevent the formation of emulsions. Detailed laboratory testing and compatibility studies of the lost SOBM with heavy brine and frac pack fluid systems helped to select suitable chemical and surfactant packages. This emulsion prevention package was pumped ahead of frac pack fluids and was an inherent part of all the fluid systems injected into formation during completion phase.
This approach and application was utilized to complete two zones in this well. Production testing and flow back of both zones indicated the absence of any emulsion issues. Laboratory testing of the recovered fluid samples confirmed the nonappearance of any emulsions. The initial gas production from each zone is more than 5 MMscf/D at a low drawdown at its planned potential. The selection and application of a suitable chemical &amp; surfactant additive system successfully prevented the emulsion problem.
Detailed laboratory studies and pre-planning helped to develop an emulsion prevention package, and its application prevented the formation of emulsions with successful production.
Simulation on the Water Controlling Performance of RPM in Hydraulic Fracturing of Low Permeability Reservoirs
Authors: Luo Mingliang , Wen Qingzhi , Liu Hongjian , Liu Jialin , Jia Zilong , Sun Hu 
Published: July 2010

AbstractHydraulic fracturing is the most effective method for improving hydrocarbon production in low or ultra-low permeability oil reservoirs, but the majority of selected wells for fracture stimulation are considered "risky" because of significant water cut increase after stimulation. Relative Permeability Modifiers (RPM) have proven to be an effective method to enhance oil recovery, especially under linear flow conditions achieved after fracturing. However, RPM treatments are not always effective. At present, the evaluation of water controlling performance of RPM is mainly based on the core flow test in lab and the actual water product after RPM treatment and the results can not provide the effective support for the RPM treatments in hydraulic fracturing, especially for low or ultra-low permeability reservoir.In this paper, the interrelations between the water controlling performance of RPM and the main parameters in hydraulic fracturing such as the properties of reservoir matrix, fracture and fluid (reservoir fluid and treatment fluid) etc, were studied using a model. The model is a radial, isothermal, two-phase, multi-component and single layer mathematical model, in which the threshold pressure gradient is considered. Through simulation, we can conclude that the most influential factors in the treatment response, i.e. the water cut reduction, are the combination of polymer adsorption type (kinetic or equilibrium) with method of application of the resistance factors (threshold or variable), resistance factor ratio, reservoir fluid properties, fracture properties and reservoir layout. On the other hand, the polymer solution rheology is not an important factor regarding the treatment response. Hence, the factors that affect the polymer solution viscosity such as shear stress, reservoir salinity and pH are of some importance with respect to drawdown, but they do not have a major influence on the response outcomes in terms of oil recovery.