bluuebunny/crossref_metadata_2025 huggingface dataset:
Regional Correlation on Saturation Height Function for Niger Delta Oil Province
Authors: Anijekwu C. , Odegbesan C. O. , Ogagarue E. E. E.
Published: December 2007

Saturation height function, a key parameter in reservoir models, is often derived from log data due to limited core data in the Niger delta. This approach culminates in lower or higher values of hydrocarbon saturation depending on nature of formation. Algorithms have been developed to predict saturation height functions required in simulation models.

The study presented in this paper was based on available rock and fluid properties from one hundred and thirty one core measurements from seventeen fields in the Niger delta oil province. Results from the derived relationships showed a good match between the derived height function and log derived saturation where there was no core measurement. They are particularly useful in partially appraised fields and exploration wells where little or no information is known about the formation type and are good for quality check of core measurements as well as Log derived saturation. Result obtained compared well with other methods. Saturation obtained from the correlation has also been used to calculate Stock tank oil initially in place (STOIIP) and free gas initially in place (FGIIP). Difference obtained in calculated volumes was 5% relative to those estimated using log derived saturations for most of the reservoirs.
A Case Study of Permeability Modeling and Reservoir Performance in the Absence of Core Data.
Authors: Ekpoudom Ofonmbuk , Obe Akin , Chike Ikechukwu , Onyekonwu Michael
Published: December 2007

Unavailability of core data in most Niger delta wells makes pertinent the need for a reliable permeability distribution.

This paper accounts for how permeability was modelled in a reservoir without core data in the Niger Delta by using five empirical approaches namely, Timur, Coates, Tixier, Udegbunam and also a correlation generated from core data of a nearby field. The five permeability results from the five approaches were used in building five different 3 D geological models.

Flow simulation was carried out for all the models to analyse their flow peformance. The permeability distribution from the correlation generated from the nearby field core data yielded a higher oil recovery.
Analyzing the Impact of Petroleum Fiscal Arrangements and Contract Terms on Petroleum E&P Economics and the Host Government Take
Authors: Iledare Omowumi O.
Published: December 2007

Abstract1

The effects of fiscal terms and system parameters on the performance profile of exploration and production (E&P) ventures and the corresponding government take under different fiscal arrangements are examined in this paper. The fiscal regimes and terms governing E&P activities and operations are incorporated into a discounted cash flow model to address questions regarding how the choices of the parameters of fiscal regime affect the economics of E&P ventures. More generally, we investigated how fiscal systems should be structured and designed to maximize government take from E&P ventures keeping in perspective the underlying economic objectives of the contractors/operators.

Using a hypothetical field as a case study, the paper concludes that government participation in E&P ventures through joint venture arrangements does not optimize economic gains for the E&P firms. Neither does government participation necessarily maximize the fair market value of petroleum resources received by the government. We also found strong evidence to suggest that the petroleum sharing contract (PSC) arrangement can be more favorable to E&P firms in terms of economic returns than the joint venture arrangement (JVA) under the general and analogous fiscal parameters and terms specified in this study. The empirical results further suggest an asymmetric response of E&P economic performance indicators to product prices, discount rate, installed capacity, and EOR. Meaning that the response of the selected indicators of economic performance in this study to positive changes in each of these inputs does not equal the response of performance indicators to negative changes in the input parameters.
An Integrated System Approach to Wellbore Cleanouts With Coiled Tubing
Authors: Rolovic Radovan , Weng Xiaowei , Hill Stephen , Robinson Geoff , Zemlak Kean , Najafov Jeyhun
Published: December 2007

Wellbore cleanouts represent the main application of coiled-tubing (CT) services. Despite a long history of utilizing CT to remove sand and other fill material from oil and gas wells, advancement in the technology, and a growing body of experience, many wells are still not cleaned adequately, some wells cannot be cleaned at all, and a downhole stuck CT or other serious problems are encountered too often. Based on gathered experience and extensive research and development of new tools and techniques, a new, highly engineered and integrated system for wellbore cleanouts was developed. This paper presents the new integrated system approach, which can eliminate wellbore fill-removal problems and provide effective wellbore cleanouts under virtually any wellbore conditions. Case studies are included that show the performance of the new system in difficult field environments.
Analysis of the Effects of Major Drilling Parameters on Cuttings Transport Efficiency for High-Angle Wells in Coiled Tubing Drilling Operations
Authors: Ozbayoglu M. Evren , Miska Stefan Z. , Reed Troy , Takach Nicholas
Published: December 2007

Coiled Tubing (CT) Drilling is becoming more popular as the drilling technology is advancing. Most of the CT applications are associated with highly inclined or horizontal well drilling. In such wells, cuttings transport is still remaining as a major challenge. In this study, a layered cuttings transport model is introduced for high-angle and horizontal wells, which can be used for incompressible non-Newtonian fluids as well as compressible non-Newtonian fluids, i.e., foams. A computer program is developed based on the proposed model. The effects of major drilling parameters, such as flow rate, rate of penetration, fluid density, viscosity, gas ratio, cuttings size, cuttings density, wellbore inclination and eccentricity of the CT on cuttings transport efficiency are analyzed. The results are verified with the experimental data obtained at The University of Tulsa – Low Pressure – Ambient Temperature flow loop. The major findings from this study are, the dominating parameter on wellbore cleaning is the flow rate, and, as the viscosity of the fluid is increased, the thickness of the cuttings bed developed in the wellbore is significantly increasing. Also, cuttings properties, fluid density, wellbore inclination and eccentricity have some influence on cuttings transport.
Tapered OD Coiled Tubing System
Authors: Kalman Mark , Domann Bob , Rosine Randy , Stephens Rodney , Chambers Michael , Martin John , McWhorter David
Published: December 2007

A Tapered OD Coiled Tubing System (TODCTS) enabling the deployment of multiple outer diameter (OD) coiled tubing sections in a single string is being developed.1 By employing larger OD tubing sections near the top of the string and smaller OD sections near the bottom of the string, the tension along the string length is reduced while maintaining sufficient flow capacity for well intervention operations. The TODCTS can enable intervention service in deeper wells or installation of multiple OD velocity strings with the diameters optimized based on well production requirements.

This paper describes the development plan, system and component design, and the results of analyses and tests conducted to verify that the the tapered connector and surface equipment meets the requirements necessary to deploy the connector and adjoining strings of different ODs.
Implications of Coupling Fractional Flow and Geochemistry for CO2 Injection in Aquifers
Authors: Noh M. , Lake L. W. , Bryant S. L. , Araque-Martinez A.
Published: December 2007

The geochemical changes caused by CO2 injection into aquifers include acidification and carbonation of the native brine and potential mineral dissolution and precipitation reactions driven by the aqueous composition changes. The latter are important for evaluating the potential CO2 storage capacity in the form of minerals and can also influence the performance of the injection well.

The theories of geochemical flows and of fractional flow provide useful insight into several aspects of CO2 sequestration. This paper gives the mathematical formalism of combined geochemical and multi-phase flow. If local equilibrium applies, the theory leads to graphical solution, from which it is easy to see when and under what conditions mineralization will occur during the injection. The theory also illustrates the influence of post-injection flow on mode of CO2 trapping (hydrodynamic, solubility, mineral, residual saturation). We also show that co-injection of water significantly alters the mode of trapping.
Coiled Tubing and Vessel Motions for Riserless Coiled Tubing Systems
Authors: Hoen Christopher , Håheim Svein A.
Published: December 2007

Special care must be taken tomaintain the integrity of the coiled tubing when performing subsea well intervention from a lightvessel without the use of a riser. In these cases the coiled tubingwill act as a riser with respect to withstanding the external loads from waves, current andvessel motions. To avoid local buckling of the coiled tubing as it enters the subsea lubricator it is important to keep the vessel positioned such that the bending of the coiled tubingis kept as small as possible.

This paper will outline a method for estimating the optimal set pointfor the vessel positionduring riser less coiled tubing operations. The method is based on a combination of measurements and analytical methods for description of the structural behaviour of coiled tubing and the subsea stack. The analytical method developed is compared to simulations using commercial riser analyses software.
Development of Gas Assisted Gravity Drainage (GAGD) Process for Improved Light Oil Recovery
Authors: Rao D. N. , Ayirala S. C. , Kulkarni M. M. , Sharma A. P.
Published: December 2007

Attempting to overcome natural gravity segregation by alternating gas injection with water has yielded better EOR performance in WAG floods than continuous gas injection (CGI) field projects. However, WAG is still a method to ‘combat’ the natural phenomenon of gravity segregation. In attempting to resolve one problem of adverse mobility, the WAG process gives rise to other problems associated with increased water saturation in the reservoir including diminished gas injectivity and increased competition to the flow of oil. The disappointing field performance of WAG floods with oil recoveries in the range of 5–10% is a clear indication of these limitations.

In order to find an effective alternative to WAG, we have initiated the development of the Gas-Assisted Gravity Drainage (GAGD) process. Unlike WAG, the GAGD process takes advantage of the natural segregation of injected gas from crude oil in the reservoir. Although gravity-stable gas floods have long been practiced in selected dipping reservoirs and pinnacle reefs, this project is aimed at a systematic development of a recovery process that would be widely applicable to different reservoir types in both secondary and tertiary modes.

The GAGD process consists of placing a horizontal producer near the bottom of the payzone and injecting gas through existing vertical wells used in prior waterfloods. As the injected gas rises to the top to form a gas zone, oil and water drain down to the horizontal producer. The new GAGD process is being developed using a three-pronged approach: (1) Design and construction of a scaled physical model to demonstrate process feasibility and to investigate and understand the interplay of capillary, gravitational and viscous forces. (2) Process optimization by determining miscibility pressures and compositions through the use of the Vanishing Interfacial Tension (VIT) technique. (3) The process demonstration at reservoir conditions by conducting horizontal WAG floods and vertical GAGD floods in 2-meter long cores. This paper will present the GAGD concept and its advantages over WAG and a summary of the experimental evidence collected so far.
Numerical Simulation of Tertiary CO2 Injection at Ivanic Oil Field, Croatia
Authors: Domitrovic D. , Šunjerga S. , Jelic-Balta J.
Published: December 2007

Tertiary CO2 injection is planned at Ivanić oil field, Croatia, in order to recover some of more than 12 × 106 Sm3 (75 MMSTB) of remaining oil in place. The field was discovered and put to production in 1963, secondary waterflooding was started in 1972, and today the field is facing a considerable decline in oil production and an increasing water cut.

A revised geological model of Ivanić field, based on 3D seismic data acquired in 1998, was used as a ground for building a full field numerical simulation model. 40 years of production history were matched sucessfully by using black oil formulation. Compositional simulation was applied for 18 tertiary injection scenarios, which investigated impact of number and position of injection wells, number of CO2 slugs, and prior repressuring of the reservoir on the predicted production profile and final tertiary oil recovery. All tertiary injection cases were compared to the base case of continued waterflooding. Simulation results indicate possibility of recovering more than 2.5×106 Sm3 (15.7 MMSTB) of incremental oil in 20 years of future production.

One of the possible sources of CO2 is the gas treatment plant in Molve, Croatia, which daily releases into atmosphere large quantities of carbon dioxide extracted from natural gas produced in northern Croatian gas fields. Sequestering a considerable amount of this CO2 in Ivanić oil field is a welcome additional benefit of the planned tertiary injection project.
Visualization of Interfacial Interactions of Crude Oil-CO2 Systems under Reservoir Conditions
Authors: Yang Daoyong , Gu Yongan
Published: December 2007

In this paper, an experimental technique is developed to study the interfacial interactions of the crude oil-CO2 systems under reservoir conditions. By using the axisymmetric drop shape analysis (ADSA) for the pendant drop case, this new technique makes it possible to measure the interfacial tension (IFT) and to visualize the interfacial interactions between crude oil and CO2 at high pressures and elevated temperatures. The major component of this experimental set-up is a see-through windowed high-pressure cell. A number of important physical phenomena have been observed when the crude oil is made in contact with CO2. They include oil swelling, lightends extraction, initial turbulent mixing, skin layer, oil drop movement, wettability alteration, asphaltene precipitation, and bubbling at the crude oil-CO2 interface. In particular, the lightends extraction, initial turbulent mixing and wettability alteration are the major characteristics of the CO2 flooding processes. It is also found that there always exists a constant low equilibrium IFT as long as the pressure is higher than a threshold value. No ultra low or zero IFT between crude oil and CO2 is found, regardless of the operating pressures and temperatures. Therefore, the measured constant low IFT and the observed interfacial interactions show that only partial miscibility between crude oil and CO2 can be achieved for most reservoirs. In addition, it is anticipated that wettability alteration may have significant effects on the ultimate oil recovery and CO2 sequestration.
Successful Cementing in Medium Radius Sidetrack Wells; Niger Delta Experience
Authors: Osazuwa Peckins Osaze
Published: December 2007

With the plan to achieve an operator aspiration of 1.76 MMBOPD by year 2004, a medium radius horizontal sidetrack campaign project was initiated by Operator to provide 33 MBOPD.

The project was planned to construct eighteen (18) wells of about 2000 bopd at an average cost of $1.5 million per well, thereby achieving lower Unit Technical Cost (UTC) of $3.2/barrel as well as maximise asset utilization of several brown fields in a particular land area.

The total capital deployed by Operator was considerably lower (1/3 of current sidetrack well cost) than for similar sidetrack well activities within Niger Delta.

The major objective was to reduce well cost by utilizing optimized medium radius technology in the construction phase of the well.

This optimized technology which includes successful cement placement without remedial activities, would reduce cost elements like total well footage and equipment installation cost per well.

The wells were horizontal with 12–45 deg/100ft dogleg severity.

The cement job evaluation reports showed excellent cement sheath placement around the liner strings and there were no remedial squeeze jobs.

A total of five wells have been drilled with good results which have had a high impact on well delivery and project execution philosophy for this Operator

This paper will focus on the five case histories, enumerating the challenges involved in the planning and execution of the medium radius well cementation with emphasis on the slurry design issues, peculiar operational challenges and a review of the milestones achieved so far in the project.
Toe-To-Heel Waterflooding: Field Scale Numerical Simulation Study
Authors: Zhao Litong , Turta Alex
Published: December 2007

Application of conventional waterflooding to heavy oil reservoirs is plagued with problems. The unfavorable water/oil mobility ratio often aggravates the negative effects of water channeling and gravity segregation. In order to overcome these difficulties, a novel process, Toe-To-Heel Waterflooding (TTHW) has been developed. The TTHW process utilizes a horizontal producer (HP) and a vertical injector (VI). The horizontal leg of the HP is located at the top of the formation and the VI is placed near the toe of the horizontal producer, in a staggered line drive configuration. The basic idea is to take advantage of the gravity segregation. When water is injected, an early water break-through from VI to the toe of the HP significantly reduces the pressure drop between VI and HP, making gravity an important factor. By gravity segregation, injected water goes to the bottom of the formation, and gradually pushes the oil upward toward the HP at the top of the formation.

The current paper is the third in a series of technical articles presenting laboratory and simulation work on TTHW in view of field applications. Results from laboratory tests demonstrated that the TTHW process was a more effective displacement process, compared to the conventional waterflooding with vertical producers and injectors. A 3-D numerical simulation study of the TTHW process at field scale using Computer Modeling Group’s (CMG) STARS reservoir simulator was conducted. Based on an inverted nine-spot pattern, the performance of the TTHW process is compared to that of conventional waterflooding under various reservoir and operational conditions.

The simulation results suggest that the best conditions for TTHW to give better performance over conventional vertical-to-vertical waterflooding are large pay thickness and high permeability. In this type of reservoirs, the water segregation due to gravity is significant, making TTHW more effective. In addition, for lower permeability (< 500 md) and higher oil viscosity (> 500 mPa-s) reservoirs, conventional water flooding is almost not applicable due to very low water injectivity. Using TTHW, the injectivity can be significantly improved, resulting in a significant increment on oil recovery. TTHW process extends waterflooding technique to reservoirs that cannot be water flooded by conventional method.
The Effect of Wettability and Pore Geometry on Foamed Gel Blockage Performance in Gas and Water Producing Zones
Authors: Romero Laura , Kantzas Apostolos
Published: December 2007

Proposal

Throughout the lifetime of oil producing wells, a common problem encountered is excessive gas and/or water production. High producing gas-oil or water-oil ratio is normally responsible for both rapid productivity decline, and increase in operating costs caused by gas or water processing. The result is often a premature shut-in of wells because production has become uneconomical. Foamed gels have been used as selective barriers to counteract disproportionate gas-oil and/or water-oil ratios in oil production. However, knowledge of the effects of critical parameters such as wettability of the porous medium and pore geometry on foamed gel-blockage performance remains incomplete.

In this work micro-scale experiments, which involve the microscopic observation of flowing and trapped foamed gel in etched-glass micromodels were performed. The purpose of the research work is to provide new insights into the sensitivity of foamed gel blockage to porous media wettability and pore geometry.

The experimental results indicated that foamed gels present higher blocking efficiency in oil-wet systems than in water-wet systems. Under experimental conditions, foamed gels exhibit higher blocking efficiency at lower pore body to pore throat aspect ratios. The plugging treatment exhibits stability after subsequent steps of gas and brine injection. Ultimately, the combination of foam and gel has both technical and economic advantages that make foamed gels superior mobility control agents.
Gel Performance Simulations and Laboratory/Field Studies to Design Water Conformance Treatments in Eastern Venezuelan HPHT Reservoirs
Authors: Herbas J. , Moreno R. , Romero M. F. , Coombe D. , Serna A.
Published: December 2007

A gel formulated for High Pressure High Temperature (HPHT) Reservoirs was evaluated for conformance treatments to reduce water production and to improve injection profiles in Eastern Venezuelan fields. The gel formulation was based on the permeability ratio reduction capacity obtained from core tests. Field tests were carried out in HPHT wells that exhibited high water cut and low oil rates. These tests showed a strong reduction in the water production and increasing oil rates, verifying the effectiveness of the formulated gel.

A laboratory study under field conditions was conducted to determine the chemical parameters to model the gel injection. The gelation kinetic and visco-elastic effects were determined using dynamic rheology, which shows the time dependence of dynamic mechanical measurements using an elasticity theory to relate the storage modulus (G’) of the gel with the crosslink number density. The obtained reaction is a third order function of phenol-formaldehyde crosslinkers concentration and 3/2 order polymer concentration. The adsorption of the polymer system was evaluated on Berea core and matched to a Langmuir Isotherm. Coreflood simulations were done to calibrate the chemical model to laboratory data.

A mechanistic field simulation study was developed with the STARS simulator using laboratory data. A range of variation of critical parameters was evaluated in the simulator in order to understand the gelation process in the reservoir. The model was used to predict the reservoir response under different gel treatment scenarios as: treatment in injector well, treatment in the producer well, and simultaneous treatment in both injector and producer wells. Idealized and field type simulation results showed a water cut reduction from 90 to 30%, matching the trends observed in wells at different locations and the gel treatment effects in typical Eastern Venezuelan reservoirs.
Water Shut-Off in Gas Wells: Proper Gel Placement is the Key to Success
Authors: Wassmuth F. , Green K. , Hodgins L.
Published: December 2007

The objectives of water shut-off treatments in gas wells suffering from water influx are to reduce water production and at the same time increase gas production rates and producible gas reserves. Several field treatments, conducted under the umbrella of a research project focused on water abatement in gas wells, have demonstrated that a sequential gel/gas injection technique in fractured gas reservoirs was successful in reducing water production and increasing gas production. Further efforts focused on improving gel placement in both fractured and matrix reservoirs to improve the treatment efficiency. Injectivity of the gelant was improved for injection into matrix reservoirs by either reducing the concentration of the high molecular weight polymer in the gelant formulation or by using a low molecular weight polymer.Gel placement was improved by displacing the gelant away from the near wellbore region with semi-stable foam rather than with gas. Such displacement allows for improved gas production after the gel treatment.Lab scale simulations were used to history-match the coreflood results to calibrate the gelation and over-displacement options in the simulations.Field scale simulations demonstrated the merits of the proper gel placement technique using a foam to displace the gelant away from the wellbore in matrix and fractured reservoirs.

Optimized gel formulations in combination with the new over-displacement technique provide a treatment alternative to combat 3-D coning situations. This over displacement technique can also minimize the start-up problems experienced in fractured gas reservoirs after gel treatments.
The Effect of Water-in-Oil Solubility on Oil Recovery in Steam Injection Process
Authors: Luo Shanqiang , Barrufet Maria A.
Published: December 2007

Water is usually considered insoluble in the oil phase, however, at the typical temperatures encountered in steam injection process, water may have higher than 40 mole% solubility in the oil phase. We developed a practical and robust algorithm for water/oil/gas three-phase flash calculation. The algorithm is based on the well-developed vapor-liquid two-phase flash calculation algorithm and avoids trivial or false solutions commonly occurred in multiphase flash calculations. We also developed a fully compositional, thermal reservoir simulator, considering water/oil mutual solubility, to study the effect of water-in-oil solubility on oil recovery in steam injection process. Simulation study shows that when water is soluble in the oil phase, it may appreciably increase oil recovery. We also found that the oil fluids should be characterized with at least 3 components for accurate compositional thermal reservoir simulation study.
Enhanced Oil Recovery by Steamflooding in a Recent Steamflood Project, Cruse ‘E’ Field, Trinidad
Authors: Ramlal V.
Published: December 2007

Based on the success of the Cruse ‘E’ Pilot steamflood, Petrotrin decided to venture into a large-scale thermal project called the Cruse ‘E’ (IADB) Expansion Steamflood. The project area consists of 270 acres in the zone of interest, the Upper Cruse ‘E’ sand. Surface and infrastructure work began in January 1994, and was followed by rig work - drilling, recompletions, and workovers. Sixty (60) new wells comprising twenty-eight (28) injectors and thirty-two (32) offtakes were drilled and completed to form twenty-eight (28) patterns. Also thirty-five (35) existing wells were utilized as offtakes. The project was commissioned in January 1996 when steam injection began. It was predicted in 1992 by reservoir simulation that 11 million barrels of heavy oil would be recovered over fifteen (15) years with production peaking in the year 2000.

However, in 1998 when oil production reached 900 bopd, the project was adversely affected by environmental concerns to a residential area in the vicinity of the steamflood and it was actually shutdown by order of the Environmental Management Agency in November 1998. Extensive environmental work was undertaken by Petrotrin in the areas of communication, training and operations to improve the safety and environmental aspects of the steamflood, and ensure that it was brought up to required environmental standards. After forty (40) months of inactivity, approval was finally obtained in March 2002 from the environmental regulatory agency to restart steam injection.

This paper discusses the performance of the steamflood during steam injection and during no injection, the operational and economic aspects of the project, and the environmental upgrade conducted. The paper also discusses the production response since restart, the amended forecast from history-matched reservoir simulation and future operating strategies.
Measurement of Three-Phase Relative Permeability with IFT Variation
Authors: Cinar Yildiray , Orr Franklin M.
Published: December 2007

In this paper we present results of an experimental investigation of effects of variations in interfacial tension (IFT) on three-phase relative permeability. We report results that demonstrate the effect of low IFT between two of three phases on the three-phase relative permeabilities.

In order to create three-phase systems in which IFT can be controlled systematically, we employed a quaternary liquid system composing of hexadecane (C16), n-butanol (NBA), water (H2O), and isopropanol (IPA). Measured equilibrium phase compositions and IFTs are reported. The reported phase behavior of the quaternary system shows that the H2O-rich phase should represent the gas phase, the NBA-rich phase to represent the oil phase, and the C16-rich phase to represent the aqueous phase. Therefore we employed oil-wet Teflon bead packs to simulate the fluid flow in a water-wet oil reservoir. We determined phase saturations and three-phase relative permeabilities from recovery and pressure drop data using the Welge method and the Johnson-Bossler-Naumann (JBN) method, respectively. The IFT range we studied was 0.03-2 mN/m. Measured three-phase relative permeabilities are reported.

The experimental results indicate that the wetting phase relative permeability was not affected by IFT variation whereas the other two-phase relative permeabilities were clearly affected. As IFT decreases the "oil" and "gas" phases become more mobile at the same phase saturations. We obtained about a 10-fold increase in the oil and gas relative permeabilities against a i00-fold decrease in the IFT.
Experimental and Numerical Study of Water-Gas Imbibition Phenomena in Vuggy Carbonates
Authors: Egermann P. , Laroche C. , Manceau E. , Delamaide E. , Bourbiaux B.
Published: December 2007

Tight gas carbonate fields are often faced with early water breakthrough in the presence of fractures connected with an active aquifer. The recovery assessment from such fields requires to take into account the role played by water imbibition of the matrix which, depending on the fracture density and rock properties, can significantly delay water breakthrough. The prediction of such spontaneous imbibition phenomena requires experimental measurements and modeling in the case of rocks of complex porous structure like vuggy carbonates. This paper gives the results of such investigation on samples from a vuggy carbonate field. A thorough petrophysical characterization of the rock was first carried out, followed by water-gas imbibition experiments. Those experiments were finally simulated numerically to check the consistency of the experimental data set and further understand the fluid flow behaviour of those peculiar media.

The porous structure of several samples was characterized from capillary pressure and NMR measurements. Spontaneous imbibition was found to be very slow, which required the implementation of a specific accurate measurement device. This slow kinetics was due to the very low mobility of water, which was measured separately as well. To explain this flow behavior, the peculiarity of the porous structure - fairly large vugs dispersed within a tight matrix with very small pore thresholds - is invoked. Simulations on a representative pore network model actually revealed that the flow ability of the water phase is considerably hindered in such type of medium. Finally, the spontaneous imbibition behavior was satisfactorily reproduced with single-porosity and dual-porosity models using the measured petrophysical parameters, thus showing the consistency of the measured data set.

Gas production management from vuggy carbonate reservoirs subjected to water encroachment requires a specific evaluation of matrix imbibition phenomenon as the latter is ruled by unconventional flow parameters linked to the complex two-phase flow interactions between vugs and micropores in such media.
Two-Stage Upscaling of Two-Phase Flow: From Core to Simulation Scale
Authors: Lohne Arild , Virnovsky George , Durlofsky Louis J.
Published: December 2007

In the coarse scale simulation of heterogeneous reservoirs, effective or upscaled flow functions, e.g., oil and water relative permeability and capillary pressure, can be used to represent heterogeneities at subgrid scales. The effective relative permeability is typically upscaled along with absolute permeability from a geostatistical model. However, the potentially important effects of smaller scale heterogeneities (on the centimeter to meter scale) in both capillarity and absolute permeability will not be captured by this approach.

In this paper, we present a new two-stage upscaling procedure for two-phase flow. In the first stage, we upscale from the core (fine) scale to the geostatistical (intermediate) scale, while in the second stage we upscale from the geostatistical scale to the simulation (coarse) scale. The computational procedure includes numerical solution of the finite difference equations describing steady state flow over the local region to be upscaled, using either constant pressure or periodic boundary conditions.

The two-stage method is applied to synthetic two-dimensional reservoir models with strong variation in capillarity on the fine scale. Results are presented in terms of both oil production rates and saturation fields. Accurate reproduction of the fine grid solutions (simulated on 500 × 500 grids) is achieved on coarse grids of 10 × 10 for different flow scenarios. It is shown that, although capillary forces are important on the fine scale, the assumption of capillary dominance in the first stage of upscaling is not always appropriate, and that the computation of rate dependent effective properties in the upscaling can significantly improve the accuracy of the coarse scale model. The assumption of viscous dominance in the second upscaling stage is found to be appropriate in all of the cases considered.
Wettability Alteration During Surfactant Flooding of Carbonate Reservoirs
Authors: Seethepalli A. , Adibhatla B. , Mohanty K. K.
Published: December 2007

Recovery from fractured, oil-wet/mixed-wet, carbonate reservoirs by waterflooding is poor. Dilute surfactant methods are being developed to improve oil recovery from fractured carbonates. This paper investigates the interactions of dilute alkaline anionic surfactant solutions with crude oil on carbonate mineral surfaces. Wettability, phase behavior, interfacial tension and adsorption experiments have been conducted. Anionic surfactants have been identified which can change the wettability of the calcite surface to intermediate/water-wet condition as well or better than the cationic surfactant DTAB with a West Texas crude oil. All the carbonate surfaces (Lithographic Limestone, Marble, Dolomite and Calcite) show similar behavior with respect to wettability alteration with an anionic surfactant. Anionic surfactants, which lower the interfacial tension with the crude oil to very low values (<10−2 mN/m), have also been identified. The adsorption of the sulphonate surfactants can be suppressed significantly by the addition of the alkali.
Physically-Based Capillary Pressure Correlation For Mixed-Wet Reservoirs From A Bundle-Of-Tubes Model
Authors: Helland J. O. , Skjæveland S. M.
Published: December 2007

It is shown that the main characteristics of mixed-wet capillary pressure curves with hysteretic scanning loops can be reproduced by a bundle-of-triangular-tubes model. Accurate expressions for the entry pressures are employed, truly accounting for the mixed wettability and the diverse fluid configurations that arise from contact angle hysteresis and pore shape. The simulated curves are compared with published correlations that have been suggested by inspection of laboratory data from core plug experiments.
Development and Application of a New Technique for Upscaling Miscible Processes
Authors: Hui Mun-Hong , Zhou Dengen , Wen Xian-Huan , Durlofsky Louis J.
Published: December 2007

Miscible gas injection offers both high local displacement efficiencies and a means for handling produced gas. As fine scale simulations of miscible processes can be very time-consuming, there is a clear need for an accurate and robust coarse scale miscible simulation capability. In this paper, we present a new upscaling technique for the accurate coarse scale simulation of first-contact miscible displacements. Our method contains two key components: Effective Flux Boundary Conditions (EFBCs) and the Extended Todd & Longstaff with Pseudo relative permeabilities (ETLP) formulation. EFBCs, which were applied previously within the context of immiscible displacements, account approximately for the effect of the global flow field on the local upscaling problems and as a result mitigate inaccuracies introduced by standard procedures. The ETLP formulation modifies the way effective fluid properties and upscaled relative permeabilities are computed in a limited compositional framework such that residual oil that is immobile and unavailable for mixing is efficiently represented.

The accuracy of the new technique is demonstrated for several example problems. Using synthetic models with differing permeability correlation lengths, we show that the new method provides results superior to those obtained using existing upscaling procedures (standard upscaled relative permeabilities, upscaled absolute permeabilities only, and nonuniform coarsening) for partially layered cases. The breakthrough time, oil production curve and saturation profiles are predicted accurately. The method is also shown to perform well over a wide range of coarsening factors (4 – 2500) for several fields with different permeability heterogeneity structures. Finally, we apply the method to a real field case with encouraging results, indicating the practical applicability of the new technique.
Coiled-Tubing-Conveyed Fracturing Technique Provides Economic Alternative To Workover Rigs in Stimulation Campaign
Authors: Allouti Achour , Amor Bachir Ben , Ferhat Ali , Oettli Mark , Ortiz Avel , Wood Jodi
Published: December 2007

In the moderate-permeability environment of the Hassi Messaoud field of central Algeria, proppant fracturing has significantly increased production, prolonging the economic life of many wells. Unfortunately, the logistics of mobilizing a workover rig to prepare the wellbore for stimulation has extended the stimulation cycle time. Additionally, many wells have tubular problems that require intervention such as squeeze cementing or tubular replacement before the stimulation process can begin. The availability of coiled-tubing equipment in the field provides the means to stimulate the wells without a workover rig. Furthermore, when coupled with a mechanical isolation system, the coiled-tubing fracturing technique protects the production tubing from high treating pressure and abrasive proppants. In the past, the lack of a reliable isolation system has limited the success of these jobs.

Reservoir conditions throughout the field allow low-rate stimulations but induce high bottomhole pressures, which make the use of conventional packers difficult. In many environments the bottomhole treating pressure creates differential pressures across the elements of a packer in excess of 9,000 psi. Several attempts to use existing packer technology yielded unsuccessful fracture treatments, and costly fishing operations were necessary to restore the wells to production. To provide an economical solution to the problems encountered by conventional mechanical packers, a new isolation system was designed. This paper provides case histories of several wells stimulated with coiled-tubing fracturing in the extreme environment of high-pressure, deep wells in the Hassi Messaoud field and examines the engineering challenges in developing a robust isolation system.
Selected U. S. Department of Energy EOR Technology Applications
Authors: Felber Betty J.
Published: December 2007

Enhanced oil recovery (EOR) innovations have paved the way for newer, more exciting technologies that provide improved EOR processes. Among the latest advancements are new methods for describing the reservoir, improved downhole instrumentation, and new chemicals engineered to improve recovery. These are just a few of the innovations available to geoscientists and engineers in their quest for better reservoir description and applications of improved EOR processes.

The U. S. Department of Energy (USDOE) has sustained development of many of these technologies. This paper highlights some of the USDOE championed laboratory and field applications work in steamflooding, biotechnology, alkaline-surfactant-polymer (ASP) formulations and chemicals to increase carbon dioxide viscosity. Future challenges in applying EOR using microhole technology are also discussed.

Advancements in steamflooding include mechanistic studies to better understand fluid and heat flow conditions. The biotechnology work discussed used resident microflora to selectively plug porous zones and increase oil recovery. The alkaline-surfactant-polymer work summarizes the laboratory and field work conducted in support of a shallow reservoir ASP application. The laboratory search for chemicals to increase the viscosity of carbon dioxide is also discussed.

A new area of work is microhole technology—wellbores that are less than 2-¼ inches in diameter. Included in this discussion are the challenges of developing the tools, the market, and the expectation of delivery of improved oil recovery chemicals utilizing a microhole.
A Novel and Successful MEOR Pilot Project in a Strong Water-Drive Reservoir Vizcacheras Field, Argentina
Authors: Strappa L. A. , De Lucia J. P. , Maure M. A. , Llopiz M. L. Lopez
Published: December 2007

The synergy between a novel biotechnological design, streamlines simulation and field-monitoring practices produced successful results in Papagayos formation, a strong water-drive reservoir of Vizcacheras field (Attachment A, Figures 25, 26, 27).

Vizcacheras field (8,636 BOPD, 162 producers) located in Cuyo Basin (Mendoza province, Argentine) started producing in 1965, involving two main reservoirs (Papagayos and Barrancas). The 60% of total Vizcacheras production is coming from Papagayos formation, which has a temperature of 198 °F, an average permeability of 1000 mDarcy, an effective porosity of 25% and residual oil saturations of 25%.

The Microbial Program started in September 1999 by a systematic inoculation in VI-286 injector using hydrocarbon degrading anaerobic-facultative microorganisms. The project was developed for along 19 months of uninterrupted treatment. The MEOR methodology used a novel approach based on low-rate injector wells serving only as a surface-to-reservoir transport link to introduce periodic batches of nutrients, biocatalyzers and microorganisms into the reservoir to colonize the contacted pore volume.

Pre- and Post-MEOR geochemical and rheological evaluations contributed to a better understanding of underlying fluid-rock-biological interactions. Fractional flow alteration in produced fluids has shown a clear improvement: oil increased and water retracted in neighbor producers of treated injector. Three dominant combined mechanisms explain this behavior: 1) further reduction of residual oil saturation by in-situ biosurfactants with low interfacial tension, 2) improved oil mobility from short-chain solvents originated by microbial alteration of heavy paraffinic ends and 3) Conformance efficiency improvement created by the colonizing biomass in active streamtubes that diverts fluids to unflooded zones.

MEOR in Papagayos formation increased the oil production rate 20% in average over baselines and the incremental reserves are estimated in 176 MBO.

The development cost of the pilot reached 2.87 $/BO and is expected to be lower than this value during future scaled stages. The present work includes an overview of the proposed expansion project, which involves two additional patterns and the current pilot injector.
Production Performance Study of West Carney Field, Lincoln County, Oklahoma
Authors: Joshi Rahul , Kelkar Mohan
Published: December 2007

The paper describes a field case study of Hunton formation in West Carney Field in Oklahoma. The Hunton formation covers 2.7 million acres in Oklahoma and in surrounding states of Texas, New Mexico and Arkansas and is one of the most prolific oil producing reservoirs in Oklahoma. The formation is geologically complex with a large number of fractures. Some of the unique characteristics of the field include decreasing GOR at the beginning of production, increase in GOR after shut-in and sustained oil rates over long periods of time. Fluid properties analysis of data obtained from laboratory tests has indicated that the reservoir fluid is volatile oil. Reservoir fluid model is generated from fluid properties data and is used in simulating the reservoir depletion process.

Production mechanism involved de-watering of the reservoir and production of oil and gas thereafter by solution gas drive. Since the reservoir fluid was observed to be volatile oil, a modified material balance method for depletion of volatile oil reservoirs was developed to calculate the initial in-place reserves and recovery factors.

A single well reservoir model was developed and compositional flow simulation was carried out using GEOQUEST E300 simulator. History matching methods were used to adjust the reservoir parameters to match the field production of both oil and gas wells. Most of the unique characteristics observed in the field could be reproduced using simulation. The model is also used to evaluate different enhanced recovery methods.
Controlling Water Production Using Gelled Polymer Systems
Authors: Willhite G. P. , Pancake R. E.
Published: December 2007

The Arbuckle reservoirs in Central Kansas are a major source of oil production. These reservoirs produce by natural water drive, yielding millions of barrels of fluid over 40 years with little decline in pressure from discovery pressures. Water oil ratios increased with time and ratios of 100:1 or higher are common when production becomes uneconomic. In the last three years, gelled polymer treatments have been used successfully to reduce water production in Arbuckle wells, prolonging the life of some wells and increasing oil recovery. Over 250 treatments have been applied. This paper describes results from a seven well program in which production wells were treated with chrome acetate-polyacrylamide gelant to reduce water production. Pressure data were obtained before the treatment to estimate reservoir permeability. Bottomhole pressure data obtained during the gel treatment provided insight into the behavior of gelant during placement. Finally, buildup data were obtained after gel treatment to determine the extent of permeability reduction to oil and water caused by the treatment. Production data following the treatments were analyzed to determine incremental oil production and correlate treatment to production response. Water production rates were reduced in every well and reductions were persistent over intervals ranging from 7-13 months. Incremental oil was produced in five of six wells treated in the program. The amount of incremental oil increased with volume of gelant injected in wells with open hole completions. Results of this test program suggest how to distinguish wells that are likely to take large treatments from those that can only be treated with small amounts of gelant. These results should improve treatment design and identify wells that are good candidates for successful treatment.