bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Small Independent Producer's Design, Construction and Operation of a Flue Gas
Authors: Godwin John , Lyons Trevor , Richardson Nancy , Olsen David 
Published: December 2007

Abstract
Driver Production was one of four companies awarded a grant from the US Department of Energy as a result of a competitive procurement for small independent producers to demonstrate economic application of gas repressurization of oil reservoirs. Driver Production proposed a Flue Gas Injection (N2 and CO2) project in a five-spot pattern in the East Edna Field, Okmulgee County, Oklahoma, USA. The paper describes the design, construction, start-up, expansion and operation of a flue gas project that uses produced natural gas as the energy source for combustion and compression. Changing the engine to a larger unit to allow for higher gas injection capacity and for injection at higher pressure demonstrated the need for critical control of flue gas quality to minimize corrosion problems associated with CO2 injection. The project has demonstrated that even small operators can successfully implement gas repressurization to increase oil production from a pressure-depleted reservoir. The project, initiated in 1996, continues to increase oil and natural gas production as long as flue gas is injected. The economics of the project and success to date have prompted the project operator and other operators who have visited and analyzed the project to consider application of flue gas in their small pressure depleted reservoirs.
P. 359
CT Imaging of Wormhole Growth under Solution-gas Drive
Authors: Tremblay Bernard , Sedgwick George , Vu Don 
Published: December 2007

Abstract
The cold production process has increased heavy oil production under primary conditions and has been applied with commercial success in the Lloydminster area, (Alberta, Canada). In this proccess, the production of sand is encouraged in order to form high permeability channels (wormholes) within the formation. The process depends on the formation and flow of foamy oil into the wormholes as these grow away from the wellbore and into the reservoir. The formation and growth of a wormhole was visualized using a CT scanner, in an experiment in which oil flowed through a horizontal sand pack and out an orifice. The only drive mechanism was the formation and expansion of methane bubbles within the live oil. The pressure gradient at the tip of the wormhole was approximately 1 MPa/m when it started to develop at the orifice. Two conditions appear necessary for wormholes to keep growing:the pressure gradient at the tip of the wormhole must be sufficiently large to dislodge the sand grains,the pressure gradient along the wormhole must be large enough to transport the sand from the tip to the orifice.
The pressure gradient at the tip of the wormhole was 2.9 MPa/m when it reached its maximum length. This suggests that, although the pressure gradient at the tip was sufficient for erosion to occur, the sand could not be carried along the wormhole causing it to stop growing. The pressure depletion experiment suggests that wormholes can easily develop in uncemented sand in the field since the maximum oil production rate during wormhole growth (18 cm3/day) was significantly lower than in the field. The minimum pressure gradient (9 kPa/m) necessary for sand transport along the wormhole is important in calculating the extent of wormhole growth in the field.
P. 367
Minimum Pseudocomponent Requirements for Compositional Thermal Simulation of
Authors: Lolley C.S. , Richardson W.C. 
Published: December 2007

Abstract
Compositional thermal simulation of heavy oils using an equation-of-state is a relatively new practice. Due to computational requirements, full field simulation using a continuous fluid characterization is not practical. Guidelines for pseudoizing lighter oils for traditional compositional simulation (typically CO2 flooding) have been investigated extensively over the last 20 years. Because compositional thermal simulation of heavy oils is a relatively new practice, procedures and guidelines for pseudoization have not been established. An equation-of-state (EOS) approach was determined to be vital to simulating the compositional dependence of K-values seen in thermal processes. A heavy oil characterization method was developed based on data from gas chromatography (GC). The GC data was then used to construct a 40 component fluid characterization as a base case for comparing pseudoized oil descriptions. For a pseudoized system to be considered acceptable, the characterization had to match PVT and laboratory data within 5% and production from the numerical simulation had to match the 40 component base case to within 10%. Based on these criteria, a minimum of 4 pseudocomponents are required to accurately simulate thermal processes and recovery mechanisms in the steamflooding of a heavy oil.
P. 383
Low Cost IOR: An Update on the W. Hackberry Air Injection Project
Authors: Gillham T.H. , Cerveny B.W. , Fornea M.A. , Bassiouni Z. 
Published: December 2007

Abstract
Air injection is commonly used as a secondary recovery process in low permeability light oil reservoirs and high permeability heavy oil reservoirs. In a new application for air injection, the W. Hackberry Project is demonstrating that air injection can be a low cost method to improve oil recovery in high permeability light oil reservoirs.
The project is testing the use of air injection in two reservoir environments:In high pressure (2500-3300 psig) reservoirs that have watered out, air injection is ongoing although insufficient volume has been injected to generate production response.In two low pressure (300-600) psig reservoirs with large gas caps and thin oil rims, air injection has generated 70,000 barrels of incremental oil production or 50% more than the normal decline.
Air injection began in November of 1994 and began producing incremental oil in July of 1996. Operating experience has taught numerous valuable lessons which can be applied to reduce the cost of future projects. Key project aspects discussed include:design and operation of air injection facilities,production operations,safety considerations, andcompletion design of injection and producing wells.
P. 401
Successful Applications of the Latest Technology for Improved Oil Recovery in Saudi
Authors: Turaiki S.A. , Raza S.H. 
Published: December 2007

Abstract
Case studies of the applications of three new technologies — 3-D Seismic, Horizontal Drilling and Multi-lateral Drilling - in Saudi Arabian Oil fields are described. Results demonstrate that:3-D Seismic surveys arc resulting in better field delineation and more accurate reservoir characterization. Better volumetric estimates result in setting realistic field development and production targets. Better reservoir characterization facies distributions and saturation domains-aids in cost-effective field development plans and efficient reservoir management programs.Horizontal and high- angle wells are aiding in producing:relatively low permeability tight reservoirs where vertical wells cannot produce at economic rates,oil pockets trapped within the random tar-filled areas of the reservoir as well as in the attic area,water-free oil from water-underlain, seemingly stagnant thin oil columns, andoil zones underlying large gas caps without excessive gas production.Multi-lateral wells are providing means to produce:low permeability tight reservoirs with each lateral draining a separate area, andhigh flow-capacity contrast multi-layered reservoirs promoting simultaneous production from various layers.
Implementation of these technologies has had a pronounced effect on reducing capital and operating costs. Development planning has become more cost-effective, oil production rate declines are being arrested' plateau oil rates are being sustained over longer duration, and oil recoveries are being improved.
P. 415
Chemical Wellbore Plug for Zone Isolation in Horizontal Wells
Authors: Saaverdra Nestor F. , Mamora Daulat D. , Burnett David B. , Platt Frank M. 
Published: December 2007

Abstract
A new technique for zone isolation in horizontal wells has been developed and tested in the laboratory. The technique consists of three sequential stages:setting a chemical wellbore plug upstream of the problem zone,spotting and squeezing a gel into the problem zone, andwashing or drilling out excess gel and the wellbore plug to clean the borehole prior to production.
Two main problems were investigated using laboratory horizontal wellbore models:placement of the wellbore plug so that slumping would not occur, andselection and testing of chemicals that could be used to make wellbore plugs with sufficiently high holding pressures.
The horizontal wellbore models consisted of PVC pipes internally lined with sand. Three chemicals, used in the oil industry for gas and/or water shut-off, were selected for the study: a monomer, a polyacrylamide, and a plastic. The x-ray CT scanner was used to obtain cross-sectional images of the plug to help understand the shear mechanisms involved.
Experimental results indicate that a plug could be placed in a horizontal wellbore with minimum slumping if the plug is introduced into a viscous completion brine pill. For the plastic plugs, the completion brine contained 100,000 ppm NaCl and 4 lb/bbl carboxyl methyl cellulose. Only the plastic plug had a sufficiently high holding pressure (343 psi for 37 in. long plug of 1 in. diameter). The experimental study indicates the proposed zone isolation technique to be viable. Research is being continued to evaluate the effectiveness of the wellbore plug during displacement of formation gels.
P. 435
Gas Shut-Off Foam Treatments
Authors: Chukwueke V.O. , Bouts M.N. , van Dijkum C.E. 
Published: December 2007

Abstract
In reservoirs with a thin oil rim below a gas cap, oil production can be severely hampered by gas coning or cusping problems. Oil production can be improved by means of in-situ generation of a gas-blocking foam barrier in the near wellbore area. Candidate wells in the Eastern Division of Shell Petroleum Development Company of Nigeria were selected for field testing Gas Shut-Off foam treatments on the basis of high Gas/Oil Ratios (GOR), low BSW, reserves availability etc. Laboratory tests were conducted to identify suitable foamer systems and construction of reservoir simulation models took place to estimate the potential of the treatments with respect to oil production and GOR reduction. Eight wells have been treated using two foamer systems and two different foam generation techniques. The results vary between a significant reduction in GOR for more than twelve months, i.e. from 7000 scf/bbl to 2000 scf/bbl at an increased oil rate from 340 to 450 bopd and treatments resulting in a minor GOR reduction for only a few weeks. It can be concluded that, on average the treatments have a 50+% success rate.
P. 459
Screening of Oil Reservoirs for Gravity Assisted Gas Injection
Authors: Lepski B. , Bassiouni Z. , Wolcott J.M. 
Published: December 2007

Abstract
Corefloods and field investigations confirmed that incremental oil can be recovered from dipping water-drive reservoirs using gravity assisted gas injection processes such as Double Displacement Process (DDP), and Second Contact Water Displacement (SCWD). Transparent cell experiments support the presumption of film flow of water-displacement-residual oil and the dependency of these methods' efficiency on fluid distribution within the pore space. The ability of oil to form a film is quantitatively expressed by the spreading coefficient defined in terms of interfacial and surface tensions of the phases involved.
The drop volume and pendant drop techniques were adapted to provide rapid and convenient methods for the measurement of IFT at high-pressure and high temperature conditions. The interfacial and surface tension properties of several fluid systems were investigated.
IFT measurements of systems used in the core-floods support the belief that a positive spreading coefficient is needed for an efficient recovery of residual oil. IFT measurements proved also that injection of nitrogen is more beneficial than methane to the creation of an oil film that controls incremental oil recovery efficiency.
The simplicity of the adapted IFT setup, combined with its ability to perform a large number of measurements, may result in the development of an empirical screening criteria needed in the selection of reservoirs suitable for DDP and SCWD processes.
P. 61
Improved Crude Oil Recovery by Alkaline Flooding Enhanced with Microbial Hydrocarbon Oxidation
Authors: Evans D. B. , Stepp A. K. , French T. 
Published: December 2007

Abstract
One low-cost improved oil recovery (IOR) technology making significant advances is reservoir flooding with mixtures that contain alkalis and synthetic surfactants (AS). Oil recovery can be further enhanced by addition of polymer to the aqueous mixture of alkali and surfactant (ASP). The neutralization of acidic oil components and formation of soap at the oil-water interface result in a reduction in interfacial tension (IFT) between the aqueous and oil phases. The process described here combines ASP with microbial technology for an innovative and cost effective technique that extends the applicability to other crude oils that may not be amenable to ASP alone. The process is based on the fact that microbes can modify crude oils and produce acid components, such as carboxylic acids, which can be neutralized at the oil/water interface by alkaline mixtures. The acid content of crude oil samples was increased in laboratory bottle tests using hydrocarbon oxidizing microorganisms, such as Arthrobacter sp. Spinning drop interfacial tension measurements between microbially treated oil and alkali/surfactant mixtures were lower than for abiotic controls (samples without microbes). For crude oil treated with Arthrobacter sp., IFT was reduced from 0.327 mN/m (abiotic control) to 0.0733 mN/m. Various strains of microorganisms were screened to begin optimizing the process, and corefloods were performed to quantify oil recovery. Laboratory coreflood experiments using microbial flooding and ASP flooding methodology showed that oil recovery was better with the combination of ASP oil recovery and microbial flooding oil recovery than with either system alone. The increased oil recovery by the microbial pretreatment recovery method correlated with an increase in the acid content of the microbially treated oil.
A Study of Microscopic Flooding Mechanism of Surfactant/Alkali/Polymer
Authors: Tong ZhengShin , Yang ChengZhi , Wu GuoQing , Yuan Hong , Yu Li , Tian Genlin 
Published: December 2007

Abstract
Two pilot tests of surfactant/alkali/polymer (SAP) and alkali/surfactant/polymer (ASP) combination flooding have achieved success in China. The one (SAP) is in Daqing oil field for the waxy oil of low acid content, and the other (ASP) is in Shengli oil field for the high acid oil. Some larger scale test projects have been planned. But the mechanisms of SAP and ASP flooding have not been studied in detail. The main purpose of this study is to support the coming larger scale test projects, so some experiment investigations (45 C) were undertaken in glass micro- models (with two kinds of wettability) to study the mechanism of SAP flooding residual oil (Daqing waxy crude oil of low acid number) entrapped in pore media. Based on the experiment results, the mechanisms of SAP flooding residual oil could be concluded as following:the deformation, drawing, stringing, emulsification (into oil-in-water emulsion) and entrainment of residual oil are the primary mechanism of SAP flooding in water-wet micro-models.
Because of the ultra-low interfacial tension (IPI) of SAP, the unremovable oil entrapped in porous media, with rigid film at interface, was turned into the movable oil of easy deformation, and was strung out continuously during moving forward. Then these oil strings were emulsified into oil-in-water droplets by shear driven force, and the emulsions were entrained by the flowing SAP solution. The phenomenon of oil stringing caused by SAP solution could be observed repeatedly in porous media. 2) pore wall transportation, bridging intra-pore or inter-pore, and emulsification into water-in-oil emulsion are the major mechanisms of SAP flooding in oil-wet micro-models. 3) sweep efficiency and displacement efficiency are improved, because of both the ultra-low IFT of SAP solution, and the emulsion diverting ASP solution into smaller pore media and the pore media beyond the main streamline besides the mobility control of SAP more favorable than that of water. 4) a SAP solution which has a low concentration of surfactant after consideration of adsorption and retention could be a successful flooding system, when it has ultra-lower transient IFT and ultra-low equilibrium IFT.
P. 91
Integration of Geological and Engineering Data to Improve Waterflood Sweep
Authors: Safley L.E. , Fowler M.L. 
Published: December 2007

Abstract
Citronelle field, an aging domestic giant oil field in south Alabama now in its mature waterflood stage, was selected for participation in the U.S. Department of Energy's Reservoir Management Demonstration Program. A reservoir management strategy was developed to extend the economic life of the field through improving operational efficiency and increasing oil production.
Waterflood optimization was identified as the primary focus for strategy development. Because the field contains over 450 wells operated by more than 100 individual well operators, the amount of well data for analysis was large and of varying quality. The approach chosen was to fully utilize existing data and select a focus area for improved reservoir characterization.
This project demonstrates how a Geographic Information System can efficiently organize and present existing well and reservoir data. Also, techniques were developed to optimize the waterflood on a local scale using a flow unit approach based on previous geological studies. Various production and injection well geometries were developed in order to identify potential wells for recompletion and conversion to injection. Additional areas in the field with recovery potential where the flow unit approach might be applied were identified.
P. 107
Permeability Predictions in Carbonate Reservoirs Using Optimal Non-parametric
Authors: Barman Indranil , Sharma Arun K. , Walker Richard F. , Gupta-Datta Akhil 
Published: December 2007

Abstract
In this paper, we have utilized a non-parametric transformation and regression technique called ACE (alternating conditional expectation) to estimate permeability from well logs at the Salt Creek Field Unit (SCFU), Texas, a heterogeneous reef carbonate reservoir. Previous attempts to derive permeability correlations at the SCFU have been less than satisfactory, leading to an over-dependence on porosity derived reservoir descriptions to predict fluid flow. Using non-parametric regression, we have now established a relationship between permeability and several common well logs that are available field-wide. These include density porosity, neutron porosity, shallow resistivity, deep resistivity and gamma ray logs. The approach adopted here also allowed US to integrate our geologic understanding of the reservoir into the non-parametric regression, further optimizing the final correlation. We have successfully predicted permeability in a majority of the uncored wells with acceptable accuracy at SCFU. These results have led to an enhanced reservoir characterization based on flow (permeability) rather than storage (porosity). This benefits both daily Operations and reservoir simulation efforts. This first, full-field application of ACE in a carbonate reservoir has demonstrated the strength and potential wide-scale use of non-parametric methods to predict permeability in heterogeneous reservoirs.
P. 129
Effective Reservoir Management with Three Case Studies
Authors: Madden M.P. , Fowler M.L. , Safley L.E. 
Published: December 2007

Abstract
Because operators generally have taken a conservative approach to reservoir management, tremendous opportunities exist for increasing production and profitability in domestic reservoirs. Recognizing the potential recovery possible because of sub-optimal reservoir management, the U.S. Department of Energy (DOE) developed a Reservoir Management Demonstration Program to increase reservoir management understanding through demonstration and technology transfer.
Three cost-shared projects were launched under cooperative research and development agreements (CRADAs). The first completed project, in East Randolph field, Portage County, OH, was in a small, newly discovered oil reservoir producing from Cambrian marginal marine sandstones of the Rose Run formation. The second completed project addressed a large, mature waterflood in Citronelle field, Mobile County, AL. Substantial progress was made on the third, in Bainville North field, Roosevelt County, MT.
Reservoir management strategies were, indeed, developed to increase recovery and profitability. At East Randolph field, gas reinjection was recommended as a secondary recovery technique over waterflood. For Citronelle field, a flow-unit approach to optimizing waterfloods using existing data was developed for the short-term strategy, and recommendations for additional data collection and analysis were developed for the long-term. In the Bainville North field, a reservoir model for simulation aided evaluation of new potential in one of several producing zones.
Each project shows the importance of developing reservoir management plans in the context of knowledge of the reservoir system, business environment, and technologies (such as affordable new PC-based programs capable of handling tasks previously requiring a mainframe). Experience also has led to valuable insights on reservoir management methodology, by identifying the general steps and considerations necessary to formulate reservoir management plans for any reservoir.
P. 143
Transport and Stability of Polymer-Producing Bacteria in Porous Media
Authors: Parli J.A. , Stepp A.K. , Evans D.B. , Bryant R.S. , Jenneman G.E. 
Published: December 2007

Abstract
Microbial systems have proven to be low-cost, environmentally safe methods for improved oil recovery. In profile modification treatments, plugging of high permeability layers of the reservoir is desirable. Microbes that produce polymers, biomass, and slimes have been shown to reduce the high permeability zones of reservoirs.
A key component for improved oil recovery by microbial methods is transport of the microorganisms. Successful placement of the microorganisms into the high permeability zones of the reservoir, without causing plugging in the near-wellbore region, is critical in permeability modification. Also important is the length of time the biopolymer remains stable within the reservoir.
Bacterial transport experiments were conducted to characterize the retention properties of several types of bacteria in different types of porous media, including oil reservoir field core (Bakken sandstone), Berea sandstone and ceramic core. Two strains of the polymer-producing bacterium Leuconostoc mesenteroides were evaluated, as well as other bacteria. Results indicate that microbial retention is higher in field core than in Berea sandstone or ceramic core and that different strains of L. mesenteroides display different transport rates and retentions. Experiments were also performed with and without growth-promoting nutrients to determine how bacterial growth affects transport. The long term stability and effectiveness of biopolymers in porous media were also examined. This paper describes ongoing laboratory investigations to evaluate microbial systems developed for permeability modification.
P. 173