bluuebunny/crossref_metadata_2025 huggingface dataset:
Optimization of Cyclic Steam Stimulation Using an Analytical Model
Authors: Tamim Mohammad , Ali S.M. Farouq
Published: December 2007

A comprehensive cyclic steam stimulation simulation study for a typical Canadian heavy oil reservoir using an analytical model which considers fracturing at the wellbore has been conducted. It is concluded that several factors are involved for successful oil recovery. The results are based on a single well operation and the process becomes more complex as well interference becomes more pronounced.

p. 457
New Oil in Old Field: Growth of North Kadi Oil Field, Cambay Basin, India: A Case
Authors: Marathe U.G. , Mandal A.K. , Ahmed A. Elias
Published: December 2007

North Kadi oil field is a major oil producing field in North Cambay Basin, India. The field discovered in 1969 is producing from high permeability sandstone reservoir of Eocene age. This reservoir is operative under active aquifer suppert. The field has about 80 m maximum gross hydrocarbon column. Preferential movement of water along certain trends, early water cut and sand incursion are some of the production problems. Till date the field has produced about 20% of OOIP. Exceptionally excellent production performance of certain wells in the eastern flank of the field located close to oil-water contact warranted a relook into the available data for possible field extension. Analysis of water encroachment trends in pay sand KS-I coupled with production performance behaviour and detail structural mapping with the help of well and seismic data indicated possibility of presence of new culminations with adequate additional storage capacity. North Kadi field which was so far depicted as a big anticlinal structure of simple type, in fact is characterised by presence of multiple small amplitude culminations and troughs. Production performance of certain wells and water encroachment trends is indicative of more available drainage area than visualised earlier. The overall pattern is suggestive of prediction of new unidentified culminations. (nearer to the low axes) which are beyond seismic resolution: to be mapped. New pool extensions are identified integrating these observations. One such culmination was drilled and proved oil bearing on the eastern flank of the structure (after 27 years of production history). Confirmation of new areas by drilling would enhance existing OOIP of the field by 14%.

P. 495
The PY-3 Field: India's First Permanent Floating Production System With Multi-Well
Authors: Bryans R.A. , Feller M.D. , Harries P.G. , Chandra Kuldeep , Bhatt A.M. , Bhandari L.L.
Published: December 2007

The PY-3 field, located some 18km offshore Tamil Nadu in the Cauvery Basin in southeast India, was discovered by ONGC in 1988. The field which lies in license CY-OS-90/l was awarded to the consortium in the 4th exploration licensing round offered in 1991.

The appraisal of the PY-3 field has shown the structure to be complex from a subsurface perspective. The reservoir comprises moderate to low quality Cretaceous sandstones of the Nannilam Formation. The sands were deposited as debriflow deposits in a trough formed by basement highs to the east and west of the field. Laterally the reservoir exhibits significant variation in reservoir quality. Variations in the overburden stratigraphy, result in large velocity variations and hence difficulty in modelling the depth to top structure which does not exhibit closure in time.

These subsurface uncertainties have been accommodated by adopting a phased development. The initial phase of development activity commenced in 1996 with first production in 1997. The development comprises subsea wells tied back to a floating production unit. A total of four wells have been used to develop the field, two of which were re-entries of existing appraisal wells.

Further development of the PY-3 field, involving potential water injection or infill drilling, will be implemented depending upon early reservoir performance.

P. 505
New Interpretation Technique for Determining Minimum Miscibility Pressure by Rising
Authors: Srivastava Raj K. , Huang Sam S.
Published: December 2007

Minimum miscibility pressure (MMP) is an important parameter for assessing the applicability of miscible gas flooding for an oil reservoir. Slim tube studies have been routinely used for the purpose in the past. In the last decade, with the advent of the rising bubble apparatus (RBA), estimation of MMP by RBA for systems exhibiting vaporizing gas drives has become more common. However, the measurement by RBA for systems exhibiting condensing gas drive or enriched gas drive behavior has remained limited in the literature. This lack possibly arises from the difficulty in associating the observed bubble behavior for such systems with MMP value. This paper presents an interpretation technique for estimating MMP for systems which may not exhibit vaporizing gas drive behavior. This single bubble injection technique has been validated by comparing measured MMP results with a slim tube study and with an empirical correlation. It is also supported by values obtained for a multiple-bubble injection technique as suggested in literature and by consistency in results when the mechanism may change from vaporizing gas to condensing gas drive.

P. 553
Fuzzy-Grey-Element Relational Decision-Making Analysis & Its Application
Authors: Yong Qidong , Hu Yongquan , Xiao Fangchun
Published: December 2007

Oil-gas field development is a complicated system, and it is a difficult to make a decision of optimal development project. In this paper, a new method which is called fuzzy-grey-element relational decision-making analysis was proposed for evaluating and optimizing oil-gas field development project based on the fuzzy matter-element analysis combined with the grey system theory. Its gist is described as the fundamental element of project by the orderly three element group consisting of "a project, an index, whiten fuzzy-grey-quantity". This group is called the fuzzy-grey-element of project. The merits and demerits of various sorts of technical and economic indexes among the projects are considered comprehensively to appraise and optimize the development projects of oil-gas field, a good effect is acquired. A case study for optimizing gas development project in China showed that the result has a good agreement with practice. Therefore, this method is a general tool and can be used in other areas of petroleum, too.

P. 649
Effect of Acid on Resin Coated Gravel in Prepacked Screens
Authors: Evans Brian , Ali Syed
Published: December 2007

The oil industry has long been concerned about the effect of acidizing wells when prepacked screens containing resin coated sand are employed for sand control purposes. Fears of unconsolidating the prepack material have often led to no acid being pumped, or small volumes that are potentially ineffective at removing deep reservoir damage. Previous compatibility tests have been performed at static conditions, where a cured resin coated gravel plug was immersed into hydrochloric and/or HCl:HF acids, and then crushed to see if any resin was removed or weakened compared to an unexposed core plug. These tests were never conducted in a dynamic condition using actual prepacked screen models until now.

Laboratory tests were performed on several prepacked screens containing either 20-40 or 40-60 U.S. mesh-cured, resin-coated gravel. The types of prepacks tested were dual-screen, single-screen, and Slim-Pak™ screen designs. The objectives of the tests were to determine whether the resin-coated gravel was damaged during the acidizing phase of a gravel-pack completion and to compare the pressure drop in the prepacks. Initially, a baseline was established showing pressure drops at various flow rates while circulating 3% ammonium chloride (NH4Cl) brine through the system without a prepacked screen. After placing a prepack in the test fixture, a baseline was established for each prepack screen with 3% NH4Cl at 1, 2, 5, 10, and 21 gallons per minute. Prepacks were acidized with 50 gallons per foot 10% hydrochloric acid (HCl) followed by 100 gal/ft of 7½ HCl and 1½ hydrofluoric acid (HF); then 200 gal/ft 3% NH4Cl.

Continuous flow rate and differential pressure were recorded using a strip chart recorder connected to a turbine flow meter and a differential-pressure transducer. Each test was duplicated to verify reproducibility. After testing, each screen was cut open so that the resin-coated gravel could be examined.
Current Materials and Devices for Control of Fluid Loss
Authors: Ross Colby M. , Todd Bradley L.
Published: December 2007

Although the traditional fluid loss control systems used in high permeability completions have received considerable discussion in literature, most of the documentation reviews the application of individual systems only; little is provided on how to evaluate which method is best suited for a given situation. This paper briefly describes the various fluid loss control systems and gives guidelines on the factors that must be considered in choosing a particular system.

P. 683
Spatial Multribution - The Art of Multiple Attribution
Authors: Kumar Rajan , Patra S.K.
Published: December 2007

Oilfield data fall in several categories. If one were to study the field behaviour from seismic data acquisition stage through simulation in light of the other, one would be confronted with the highly daunting task of studying some data in the light of other, another chunk in conjunction with yet another and so on. Leave aside the actual data, the database structure itself can run in hundreds of tables and yet remain incomplete. So, the complexities involved are all too obvious. Every time database designs are looked upon from managerial points of view, and as they pass through different managers, a need to restructure them is felt. Different managers have different ways of looking at the data and different corners on which to lay stress upon. Understandably, in a multidisciplinary environment, if one were satisfied with the outputs, other would only be partly satisfied while there may be someone not at all subscribing to the ideas. This is where a strong need to create junction to cross roads is felt. But the questions are i) Is it possible? and ii) Is there a solution which respects all the disparities and brews them into a meaningful concoction? This paper attempts at suggesting some solutions.

P. 669
Water Injection in Water-Wet Fractured Porous Media: Experiments and a New Model
Authors: Terez Ivan E. , Firoozabadi Abbas
Published: December 2007

This study examines water injection in water-wet fractured porous media and its modeling using the Buckley-Leverett theory. New experimental data on water injection in Berea and Austin chalk matrix block(s) are presented. Water injection in Austin chalk with a permeability of 0.01-0.04 md and porosity of 5% results in about 20% recovery from the rock matrix.

In the second part of the paper, we use the Buckley-Leverett displacement in a dual-porosity model to simulate the the literature data as well as the experiments presented in the first part. A new model is devised for the simulation of water injection in fractured porous media. A major element of the new model is the multiplication of the transfer flux by the fracture saturation with a power of 1/2. This simple model can account for both co-current and counter-current imbibition and it is computationally very efficient. The results of the proposed model and the fine-grid simulation are in good agreement with the experimental data.

P. 21
Reviewing the Strategy of Steamfloods in a Dipping Reservoir
Authors: Mastmann M. , Fabel G.
Published: December 2007

Steamflooding is the preferred enhanced recovery method in several medium heavy oilfields located in northwestern Germany next to the Dutch border (Emsland area). BEB, PREUSSAG ENERGIE and WINTERSHALL began their first steamflood project in the Georgsdorf field in 1975, followed by similar projects in the Ruehlertwist, Emlichheim and Ruehlermoor fields.

In the Georgsdorf field operated by BEB, several steam-flood projects were designed as pattern floods in a variable dipping sandstone reservoir at a depth of 2300 ft. Standard practice is to inject the steam below the center of a dipping steamflood pattern. In this field however, steam injection near the center of the pattern with a temperature of 600 0F and a steam quality of nearly 100 % created problems in the updip producers. These wells often steamed out early in the life of the project. The wells had then to be produced at reduced rates with a maximum wellhead temperature of 212 F (government limitation). Incremental production was mainly observed in the downdip wells due to gravity effects of the steam condensate.

A joint team of geologists, reservoir. and production engineers from BEB and Preussag Energie was formed to evaluate the feasibility of future steamflood projects. This included a review of the performance of the existing projects with respect to the location of the steam injectors. The team recommendation was to locate future steam injectors updip at the top of the structure. By moving the location of the steam injector updip, calculations in comparison to existing projects indicated a significant improvement in the incremental steam/oil ratio. This technique is contrary to the standard recommended procedures.

P. 59
Results of the Injection Well Polymer Gel Treatment Program at the Rangely Weber
Authors: Hild G.P. , Wackowski R.K.
Published: December 2007

The Rangely Weber Sand Unit is a large CO2 miscible WAG flood located in northwestern Colorado. Conformance improvement has become the key operating strategy due to the maturing flood's associated natural increase in operating expense and declining oil production. Conformance improvement is defined as improving the vertical and areal sweep of the reservoir and is one of the few strategies that will reduce operating expense and allow for the recovery of additional reserves.

The many different technologies and techniques that have been deployed over the last decade to improve the conformance of the reservoir include: selective injection equipment, straddle packer assemblies, pattern re-alignment, cement squeezes, foam treatments, reduced half cylcle slug sizes, simultaneous injection, and polymer treatments. These attempts have met with varying degrees of success.

Recent efforts using large volume (10,000 bbl) polymer gel treatments to treat injection wells have been very successful. This success is attributed to the fact that these treatments effectively impact the deep reservoir problem. Past near-wellbore treatments were not effective at preventing flow in the high permeability matrix and fracture pathways believed to be responsible for poor sweep.

Results from 44 injection well treatments performed through mid 1997 are discussed. Individual treatment examples and full project economics are provided. Field modeling and forecasting to assess the impact of continued treatments over the next ten years is also included.

P. 93
A Successful ASP flooding Pilot in Gudong Oil Field
Authors: Zhijian Qu , Yigen Zhang , Xiansong Zhang , Jialin Dai
Published: December 2007

An ASP flooding pilot of close well spacing in Gudong Oilfield was conducted successfully. The producers appeared obvious responses to the ASP flooding. The ultimate oil recovery increased by 13.4% OOIP.

This paper describes the whole process of the ASP flooding and the analysis of the reservoir performance based on the injection/production data, single well tracer surveys, carbon/oxygen log, sealing core drilling and monitoring the properties of the fluids. By means of the numerical simulation, the distribution and characteristics of various fluids are demonstrated.

P. 107
Effect of Wettability on Oil Recovery by Near-miscible Gas Injection
Authors: Wylie Philip , Mohanty Kishore K.
Published: December 2007

Oil can become bypassed during gas injection as a result of gravitational, viscous, and heterogeneity effects. Mass transfer from the bypassed region to the flowing gas is dependent upon pressure-driven, gravity-driven, and capillary-driven crossflows as well as diffusion and dispersion. There exist a number of factors that influence these mass-transfer mechanisms, including gas enrichment, injection methodology, orientation of the mass-transfer region, water saturation, and wettability. The focus of this study is on the influence that wettability has on bypassing and mass transfer. Experimental results reveal comparatively less bypassing occurs in a strongly oil-wet sandstone than in a water-wet sandstone for gravity-dominated, secondary gasfloods. Mass transfer under oil-wet conditions is enhanced, as a result of oil-wetting film connectivity, over that of water-wet conditions, where water-shielding is significant.

P. 169
A Case Study in Scaleup for Multi-contact Miscible Hydrocarbon Gas Injection
Authors: Jerauld G.R.
Published: December 2007

This paper describes the strategy and results of scaleup done to simulate a multi-contact miscible hydrocarbon WAG injection process. To adequately model both oil recovery and solvent retention in WAG, one must model three-phase flow including gas trapping. Scaleup of the multi-contact miscible gas process is particularly difficult because of the very fine- scale structure of the gas fingers and the miscible front. The case studied is a heterogeneous mixed-wet reservoir with a transition-zone down to an underlying aquifer. The objective was to develop pseudo relative permeability curves and other parameters which are suitable for running in a full-field limited-compositional model with 3 hydrocarbon components.

Both history-matching and more systematic approaches were used to generate pseudo relative permeability curves which reproduced results of high-resolution, fully- compositional reference simulations, Dynamic pseudoization techniques were used to derive first guesses at pseudo relative permeability curves, but required further calibration to successfully reproduce finer-grid, fully-compositional reference simulations. In matching incremental miscible-gas oil recovery timing and solvent retention, varying three-phase water relative permeability was much more effective than varying the mixing parameter in the limited-compositional model.

The predictive capability of pseudos was tested for changes with respect to slug size, WAG ratio, and solvent enrichment. Pseudos derived for one pattern or cross-section were tested in other patterns or cross-sections. Pseudos worked well with respect to changes in WAG ratio, fairly well with respect to changes in solvent enrichment, and moderately well for changes in slug size. They were less robust with respect to changes in description.

P. 219
Integrated Phase Behaviour Modelling of Fluids in Reservoir-Surface Processes Using
Authors: Gozalpur F. , Danesh A. , Todd A.C. , Tehrani D.H.
Published: December 2007

Compositional reservoir simulation is widely used in the design of improved oil recovery (lOR) schemes, in particular for gas injection and gas cycling studies. An integrated modelling approach, using a single equation of state (EOS), to describe fluid phase behaviour and properties within the reservoir, flow lines and process facilities is an attractive option for reservoir management. Low computational times for flash calculations is an important element in compositional reservoir simulation. Grouping of fluid components reduces the computational time, but the approach is not suitable for the integrated modelling, where detailed compositional information on produced reservoir fluids may be required in the design and operation of fluid processes at the surface.

If binary interaction parameters (BIP's) are not used in an equation of state, the number of equations in phase equilibrium calculations will reduce to three, regardless of the number of components. This will reduce the computational time markedly. However, the current practice in the industry is to calibrate, or tune, EOS models against experimental data by mainly adjusting BIP's.

In this paper, based on the approach which avoids using BIP's, a rapid flash calculation method has been evaluated and its convergence has been improved for gas condensate reservoirs. To improve the EOS prediction within a wide range of temperature, the temperature dependency function of the attraction term () was also modified. A practical tuning method has been developed which is consistent with the proposed function. The presented integrated tuning method can be applied to match the experimental data of different types of fluids within wide ranges of temperature and compositional changes using any EOS. The reliability of the proposed method and the associated saving in computing time, in comparison with conventional methods, are demonstrated in this work for a variety of fluids.

P. 277
Water Shut-off Field Experience with a Relative Permeability Modification System in
Authors: Faber M.J. , Joosten G.J.P. , Hashmi K.A. , Gruenenfelder M.
Published: December 2007

The Marmul field in Oman is exhibiting a low oil recovery caused by the high oil viscosity (80 mPa.s) and the moderate to strong edge water drive. The poor mobility ratio has resulted in early increased water production through water channeling and coning. The technology evaluated to reduce the water production made use of a so-called relative permeability modifier system which was composed of a cationic polyacrylamide and the crosslinker glyoxal. This gel system reduces the relative permeability for water, while only marginally affecting the relative permeability for oil. The aim of a relative permeability modifier system is a decreased water production and potentially an increased oil production. The major advantages for such a system are that the treatment is bullheaded down the well and detailed information on the inflow performance is not required. This was advantageous for the Marmul field in which all the wells have been gravelpacked. Selection criteria were used to establish which wells would be treated and the final candidates were randomly located over the field. The treatment design consisted of the injection of three equal sized polymer/crosslinking stages with increasing polymer concentration. Five of the initially six treated wells showed a positive response to the gel treatment, i.e. (large) water-cut reduction and increased oil production. A simulation study on one of these treatments was performed to understand the behaviour of these treatments. Initial results could not match the observed field behaviour and only after introduction of flow barriers (shale layers) in the reservoir model a match between simulation and field could be achieved showing the significance of small details in local geology around the well. However, these flow barriers could not be seen on the open hole logs. Subsequently eight treatments have been performed. However, they were disappointing and no clear explanation for the deviating behaviour could yet be given. The causes for the poor performance could be poor candidate selection and/or a poor understanding of the gel system. Poor candidate selection is considered doubtful because the wells in the first six and the last eight treatments were randomly chosen throughout the field. Therefore, the emphasis is now on the gel system to determine more accurately its chemistry (e.g. polymer/crosslinker concentrations needed) and the volumes required to obtain an optimum result with respect to decreased water production and increased oil production.

P. 307
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

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

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

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

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

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

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

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

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

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

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.

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Integration of Geological and Engineering Data to Improve Waterflood Sweep
Authors: Safley L.E. , Fowler M.L.
Published: December 2007

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.

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Permeability Predictions in Carbonate Reservoirs Using Optimal Non-parametric
Authors: Barman Indranil , Sharma Arun K. , Walker Richard F. , Gupta-Datta Akhil
Published: December 2007

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

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

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
Selective Conformance Control in Heterogeneous Reservoirs Using Unstable, Reactive
Authors: Thompson K.E. , Kwon O.
Published: December 2007

This paper examines a conformance control technique in which gel is placed into a heterogeneous porous medium by first injecting a high-viscosity uncrosslinked polymer solution and second, a low viscosity crosslinker. The latter step causes an unstable displacement to occur and allows the crosslinker to flow selectively into high-permeability strata. A visual flow cell was used to test the procedure, and complete fluid diversion was achieved in a dual-zone medium with a 4:1 permeability ratio. In addition, experiments and numerical simulations were used to study fundamental changes in viscous fingering due to the crosslinker-polymer reaction. When the crosslinking reaction is fast enough so that it occurs during injection, the viscous instability becomes somewhat damped, resulting in less distinct fingers and a nearly plug-flow displacement in some cases. The differences are because gelation causes a large pressure gradient to form just behind the displacement front, whereas unreactive fingering is characterized by the formation of a small pressure gradient within the fingering zone.

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