bluuebunny/crossref_metadata_2025_split huggingface dataset:
Enhanced Recovery for Selected Components of a Highly Volatile Oil
Authors: Papp I. , Lakos B. , Palasthy S. , Tromboczky S. 
Published: December 2007

Abstract
The Tisza-l reservoir is located in the uppermost formation of Algyo oilfield the largest hydrocarbon field of Hungary. The oil of this reservoir has extreme characteristics: Boi = 3.94 m3 /m3 Rsi = 711 m3 /m3 at the initial pressure of 169 bars and temperature 92 C. The specific gravity of the crude is 0.728 t/m3 (63 API). It is caused by the high amount of intermediate components: the C3 - C6 content is about 34 mol% in the live reservoir oil. The reservoir has been produced since 1992, while the pressure has declined 6.5 bars. The oil recovery is 24%. The main factor in the reservoir mechanism is the strong bottom water drive.
Using a 3D full field reservoir simulation, high ultimate recovery (48%) was predicted. The total pressure drop was only 20 bar because of the strong water influx. This process is not typical for such a type of reservoirs. The ultimate recovery for the intermediate components was almost the same as the oil recovery (about 50%) because of the high abandonment pressure.
To enhance the recovery of the intermediate rich solution gas, when the water cut reaches at a certain high level, dry hydrocarbon gas is intended to inject into the reservoir at the contours. The solution gas of this type of oil is liberated in presence of dry gas in accordance with the results of phase equilibrium calculations and PVT measurements at high pressures, too. Thus, the remaining oil will be vaporized by the injected dry gas. The enriched gas will strengthen the segregation drive migrating on the top of the reservoir Because of the technical environment, only hydrocarbon gas can be applied to realize the above technology.
The advantage of the above mechanism has been proved by compositional full field simulation. The results of calculations show 10-13% additional recovery in C3 - C6 components. The excellent infrastructure available in the field provides a possibility to realize the above technology with a minimal amount of investment.
P. 355
The Importance of Reservoir Characterization in the Belida Field Development
Authors: Hepler G.F. , Gaynor J.M. , Thornton M. 
Published: December 2007

Abstract
The Belida Field located in the western portion of the South Natuna Sea, was discovered in December 1989, produced first oil in October 1992 and reached a peak rate of 130,000 BOPD in June 1994, 54 months after discovery. A risk-tolerant business strategy was applied to increase the net present value of the Belida field by reducing cycle time. Management assigned a multi-discipline reservoir team to the task of identifying the critical uncertainties and formulating a reservoir characterization that would support a value driven development plan. Critical concerns included structure, interconnectivity of the sands, sand strength, effectiveness of aquifer support, and the ability of 3-D seismic to define the field limits. The reservoir description and subsequent development activity focused on addressing the critical uncertainties and applying best practices to maximize value. Frequent team reviews and oversight by a supportive management enabled the team to exceed its economic goals.
The Belida Field has estimated reserves of over 300 MMBO, and as of November 1, 1997 has cumulatively produced over 172MMBO, almost 60% of the field reserves. The field is currently producing at a rate of 87,000 BOPD. The estimated development cost in the Plan of Development was projected to be ﹩800 million or approximately ﹩2.67 per barrel. The total investment was reduced to ﹩540 million for a resulting development cost of ﹩1.80 per barrel. Conoco, its partners, and the Indonesian government have realized increased value with a higher than predicted reserve case, lower overall costs due to optimization and the benefits of decreased cycle time.
P. 63
Technical and Financial Success in the Rejuvenation of the Matured Baram Field
Authors: Bin Mohamad Ali Junaidi , Bin Sulaiman Mustafa , Bin Husin M. Taufik , Elk Jan V. 
Published: December 2007

Abstract
This paper discusses the effectiveness in the use of a risk management strategy, cost containment and application of proven technology in the further development of the matured and complex Baram field. This paper shows how with the integration with the key elements such as a focused team, sound drilling and completion philosophy led to a successful rejuvenation of the field.
The Baram field is the most complex field of the nine fields operated by PETRONAS Carigali Sdn Bhd and has been developed since 1970. This field has been under continuous development for the past 25 years producing at 60000 barrels of oil per day (BOPD) at its peak and declined to some 10000 BOPD in 1987. A development campaign was planned to develop some 83 million stock tank barrels (MMSTB) of reserves with the financial commitment which amounted to U.S. $199 million money of the day (MOD) in 1991. A focused team was responsible to ensure the progress and success of the campaign.
After the drilling campaign, the field is currently producing at its peak of 62000 BOPD, more than it has ever produced before. This recent further development of this field was carried out in 1994 and 1995. Although the campaign was carried out three years later than planned, the team has managed to execute the campaign at U.S. $20 million below the budget and while so doing, achieved a few drilling world records.
P. 85
Development Of Aquifer Influence Function for Undersaturated Oil Reservoir Using
Authors: Menissi Moh. H. , Kenawy F.A. , Mohamed S.A. , El Sallaly M.E. 
Published: December 2007

Abstract
Many oil and gas reservoirs have their associated aquifers, which provide them with some pressure support and form a hydraulic system. When material balance calculations are applied to such reservoirs, aquifer behavior models are required. In practice, the most common procedure is to assume an aquifer model, which has an analytical solution that can readily be implemented. The simplest methods are based on the Steady State (Schilthuis), Modified Steady State (Hurst), and the Unsteady State (Van Everdingen and Hurst), models. For correct description of the hydraulic system using the available techniques, it is required to have a minimum set of information about the reservoir and aquifer, such as: viscosities, compressibilities, permeabilities, volumetric factors, and geometry of aquifer and reservoir. To overcome possible lack of some of this information, the technology of aquifer influence function "AIF" has been developed and therefore employed.
Most of the previous work was mainly concerned with AIF models for gas reservoirs. This study has focused on devising a methodology for assessing water influx into undersaturated oil reservoirs based on AIF models. After developing the AIF model, it was validated using actual field data and then applied to four real field cases from the Gulf of Suez region. The results of this application have shown that, the developed model can generate an accurate aquifer influence function for the given reservoir that may directly be extended for future predictions of the reservoir and aquifer performances. The model results have indicated good agreement with actual field data. The model required some basic historical data to run without assumption of reservoir and aquifer rock and fluid properties or aquifer geometry.
The semi-analytical approach devised in this work, with Levenberg-Marquardt Non-Linear technique, provided a quick, easy and yet accurate procedure for calculating the aquifer influence function. Four field cases have been studied in this work, namely: October-Nubia, October "J"-Nubia, October "J"-Asl, and Ramadan-Nubia "C" reservoirs. Confirmed by the actual field studies, for different reservoir- aquifer geometry and strengths, the model has proven to be capable of:evaluating the reservoir-aquifer performance,defining an appropriate AIF, andpredicting reservoir pressures under varying production schemes.
Sensitivity cases have also shown that better description of the aquifer influence function model can always be achieved and consistently improved by using additional production data when available.
P. 219
Inflow Performance of a Stacked Multilateral Well
Authors: Permadi P. , Wibowo W. , Permadi A.K. 
Published: December 2007

Abstract
The use of multilateral well is becoming an emerging method to improve oilrecovery efficiently. A stacked multilateral well can produce fluids from twoor more separate productive zones. Unlike a commingled vertical well, inflow performance relationship (IPR) of a multilateral system is influenced by wellbore hydraulics of the horizontal boreholes. As a rock and fluid properties may vary considerably from one zone to another, construction of the composite IPR would become a necessity in an effort to evaluate and optimize the production performance.
The purpose of the present study is to investigate the effect of pressure losses along the horizontal wellbores on inflow performance of a multilateral well system. A mathematical model is used here to calculate pressure losses within the weilbores and the productivity indices as well. A procedure to construct the composite IPR of a multilateral well and a method to predict the production decline are presented.
A parametric study of wellbore hydraulics of a multilateral well system has been conducted. In general, results obtained show that increasing pressure losses in the lateral holes leads to the IPR curve shifting downward and reduced daily oil production. These demonstrate that production rate estimation for a given multilateral well would be too optimistic when pressure losses are omitted. No such work on stacked multilateral wells has been reported in the pertinent literature.
Overall, this paper provides some information to better understand the application of multilateral well technology and to improve our knowledge of the importance of wellbore
P. 245
"Survival of the Fittest" an Optimized Well Location Algorithm for Reservoir Simulation
Authors: Santellani G. , Hansen B. , Herring T. 
Published: December 2007

Abstract
Traditionally, the optimization of well locations using a numerical simulator is time demanding and based on a manual trial end error process. This paper develops an automated technique to locate production wells.
The automatic process is based on an algorithm that combines a 3-D simulation model with an external optimization code. The process is genetic in nature. Starting from a maximum well count, it proceeds in steps selecting a set of wells at the end of each 3-D simulation forecast and stops when a desired number of producing wells is reached.
Two applications of the automatic well location process are presented.
The first example considers the Ekofisk field, the largest oil field in the Norwegian sector of the North sea, with more than 20 years of production, water and gas injection. In this case, 32 new well locations have been automatically identified. The second example applies the process to the Smorbukk field, a very complex sandstone reservoir with oil and gas condensate layers and dry gas reinjection. 18 well locations have been automatically defined and connected to 6 subsea templates.
In both cases, it has been possible to manage specific topics related to the field and to obtain a large increase in the economic value, accelerating the production and increasing the final field recovery significantly.
The total process run time does not exceed 24 hours.
This new methodology proved to be reliable and quick and is strongly recommended in studies where complex simulation work is required to optimize well locations and when different geological descriptions and development scenarios have to be verified in short time, such as geostatistical realizations.
The technical advantages of such a process are:–Consistent methodologies allow for true comparison between models.–Added value and reserves when compared to the traditional manual procedure.–Significant time saving.
P. 255
Scaleup of Geological Facies for Multiphase Flow Simulations
Authors: Tambe D.E. , Chopra A.K. 
Published: December 2007

Abstract
A major challenge in understanding and predicting the performance of petroleum reservoirs is to describe their geologic and their petrophysical heterogeneities realistically and to represent the described heterogeneities in a reservoir simulation model. Detailed and realistic reservoir models usually incorporate several geologic facies or lithotypes, each exhibiting unique relative permeability and capillary pressure characteristics which must be accounted for during numerical simulations.
This paper describes a steady-state methodology to generate effective multiphase flow functions (relative permeability and capillary pressure) and pseudo functions for reservoir models consisting of multiple geologic facies. The generated effective flow functions capture the variations in geologic facies and petrophysical heterogeneities that control reservoir performance. The technique can be used to scale up complex geologic models for reservoir simulators. This steady-state approach is significantly faster than other techniques requiring multiphase flow simulations.
The technique was applied to scale up a realistic 3-D reservoir description of a complex fluvio-deltaic sandstone reservoir. The generated effective flow functions were used successfully to reproduce truth case' performance predictions (oil recoveries, pressure profiles, and water production) for a quarter 5-spot and a quarter 9-spot pattern. The generated effective flow functions depend largely on the permeability distribution, the spatial distribution of geologic facies, and the relative proportions of the geologic facies in the reservoir model.
P. 301
Reservoir Characterization, Geological Modeling, and Reservoir Simulation of the N'Sano Field, Upper Pinda Reservoir
Authors: King G.R. , Costa R. , Minck R. , Leggett E. , Carleton B. , Laidlaw C. , Domingos F. 
Published: December 2007

Abstract
N'Sano field is located offshore of the Angolan province of Cabinda in approximately 250 feet of water. The N'Sano field, discovered in October 1992 with Well 44-08X, is comprised of three non-communicating, oil-bearing horizons: the Upper Pinda reservoir, the Vermelha reservoir, and the Likuoala reservoir. The Upper Pinda reservoir of the N'Sano field was deposited in a flat, cyclical, near-shore marine environment. Consequently, the U. Pinda reservoir is characterized by a highly stratified sequence of sandstones, carbonates, and shales. The vertical correlation lengths of the various reservoir and non-reservoir facies are between 0.5 - 20.0 feet.
Due to the stratified nature of the U. Pinda reservoir, a highly detailed reservoir characterization and geological modeling effort was conducted in support of a reservoir simulation study. To incorporate the complex reservoir geology, a facies based approach was used for the reservoir characterization and geological model construction. For the purpose of geological modeling, nine lithological facies were identified from U. Pinda core. All reservoir property relationships (log porosity estimators, porosity-permeability transforms, capillary J-functions) were derived on a facies basis.
A 52x68x329 (1,340,144 cell) geocellular model of the U. Pinda reservoir was constructed for the geological study. Geostatistical techniques were used to populate the geocellular model. Vertical variograms were obtained from well logs. The log coverage in the U. Pinda reservoir in N'Sano was determined to be sufficient to provide good estimates of the vertical variograms. Areal variograms were obtained from a reservoir continuity study. Reservoir continuity, correlation lengths, and directionality of the nine lithological facies were obtained from this study and converted into areal variograms.
The geocellular model was then upscaled to a 35x45x40 (67,200 total cell/43,010 active cell) reservoir simulation model. In order to preserve the stratified nature of the reservoir, the geological model was upscaled using the dynamic scale-up technique of Durlofsky et al. The simulation model was then history matched with two years of primary recovery and three years of secondary (waterflood) recovery.
This paper will discuss in detail all phases of the study including: the reservoir characterization, geological modeling, model scale-up, history matching, and predictions.
P. 317
Laboratory and Theoretical Studies for Acid Fracture Stimulation Optimization
Authors: Navarrete R.C. , Miller M.J. , Gordon J.E. 
Published: December 2007

Abstract
The success of an acid fracturing treatment is determined by two characteristics of the fracture formed by the acid reaction: length of the conductive fracture and conductivity of the fracture. The distance that reactive acid moves along a fracture is controlled by the competition between the acid fluid loss and the rate of acid reaction with the formation versus the acid flow rate along the fracture.
Acid conductivity experiments were performed with a unique conductivity instrument using limestone samples designed to simulate this complex process. Special emphasis was placed on scaling the processes described. Two different acid systems were compared: inhibited 28% HCl and emulsified 28% HCl at 130 F and 215 F. Results show that emulsified acid is 8.5 times more retarded than straight acid and that emulsified acid provides a more efficient use of the acid capacity, allowing for longer fracture length without sacrificing fracture conductivity.
An acid fracturing simulator was used to illustrate the effect of acid retardation on the resulting etched fracture. The simulator computes many operating parameters which enables the systems to be compared under realistic field conditions. The emulsified acid is most beneficial at high temperatures, where it generates greater etched half-lengths than HCl even at substantially lower injection rates.
P. 231
Advanced Fracturing and Reservoir Description Techniques Improves Economics in Utah, Green River Formation Oil Project
Authors: Schubarth S.K. , Yeager R.R. , Murphy D.W. 
Published: December 2007

Abstract
The Green River formation in the Utah Basin of eastern Utah is a series of low-permeability sands containing a viscous crude oil. Primary stimulation techniques involve the pumping of hydraulic fracture treatments. Usually several treatments are pumped per wellbore because, the sands are spread out over a large vertical interval. Typical treatments use a crosslinked Borate fluid with high proppant concentrations and moderate volumes of sand as proppant.
The operator's changes in fracture treatment design were evaluated through comparisons to offsetting well production responses. The results indicate a 65% improvement in early, six-month, oil recovery and improved effective stimulations versus prior development projects. These results are primarily due to increasing the fracture conductivity through more effective proppant placement. Descriptions of the fracture treatment designs and predicted fracture geometry using fracture computer models will be presented. The economic impact of the increased production response has added $60,000 of additional revenue to early response while fracture treatment costs have actually declined.
The paper will also detail the reservoir description work that has been performed to quantify the production response from individual sands in the Green River formation. This work will further improve economics by allowing true fracture optimization for individual treatments. The reservoir description technique uses standard openhole log suites and results in a prediction of in-situ formation permeability for individual sands. The technique has proven very accurate in predicting well production response and these results will be presented. The authors believe that the methodology used can be applied to similar reservoirs to achieve similar results.
P. 249
Permian Basin Field Tests of Propellant-Assisted Perforating
Authors: Miller K. K. , Prosceno R. J. , Woodroof R. A. , Haney R. L. 
Published: December 2007

Abstract
The use of a new propellant-assisted perforating technology will be discussed. Two cases, one producing well and one injection well, are reviewed to illustrate successful and unsuccessful results in the Howard Glasscock Field of Howard County, Texas. The technique employs a propellant sleeve that slides over conventional perforating casing guns and generates a rapidly expanding gas force upon gun detonation. The two case studies are from the San Andres and Queen formations. Perforating, acid breakdowns, hydraulic fracturing and radioactive tracer work done in conjunction with the jobs are reviewed. Comparisons will be made with other offset wells in the same formations. Production and injection results, as well as insights regarding future applications of the technique, will be provided.
Cost Effective Method for Improving Permeability in Damaged Wells
Authors: Tjon-Joe-Pin Robert , DeVine Carolyn S. , Carr Michelle 
Published: December 2007

Abstract
Polymeric damage is due to inconsistent or incomplete breaks of stimulation fluids as well as dynamically formed filtercakes produced by drill-in fluids or drilling muds. Several methods have been employed with limited success to remove polymeric damage in an effort to increase well productivity.
Prior treatments to remove this type of damage consist either of bleach (sodium hypochlorite) or acids. In case of horizontal wells with slotted liners or screens bleach or acids are not preferred. Additional expensive trips have become mandatory when coiled tubing or drill-pipe are utilized for spotting the treatment. Additionally, the mineralogy of some formations precludes the use of acids.
Recent extensive research was conducted to develop a treatment which could effectively reduce this type of polymeric damage in either horizontal or fracture stimulated wells. Core flow evaluations and regained conductivity testing have shown that multi-fold improvements can be achieved even at elevated temperatures exceeding 250 F and over a wide pH range.
A case study of several low productivity wells suffering from polymeric damage was conducted. Post-frac production histories and return flow analysis were evaluated to characterize the damage and guide the remedial treatment design. A detailed study of field case histories including 11 fracture stimulated wells, which were suffering from polymeric damage, are presented and demonstrate how multifold improvements in well productivity could be achieved.
P. 297