bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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 (&lt; 500 md) and higher oil viscosity (&gt; 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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.