bluuebunny/crossref_metadata_2025 huggingface dataset:
Foams for Mobility Control and Improved Sweep Efficiency in Gas Flooding
Authors: Zhu T. , Strycker A. , Raible C.J. , Vineyard K.
Published: December 2007

This experimental investigation studied the use of additives to enhance foam properties and improve the in-situ generation of foams for improving gas flooding sweep efficiency. Some of the parameters affecting foam performance were polymer concentration, different surfactants and their concentration, aqueous phase salinity and pH, and effect of flow rate (or shear rate).

Performance of polymer enhanced foams (PEF) was much better when compared to conventional foams. Polyacrylamide polymers were used as an additive. Higher foam resistance and longer foam persistence were achieved by using relatively low concentrations of polymers. The studies also showed that the foam performance was significantly improved over a broad range of polymer concentrations.

A number of other investigators have shown that foams are severely affected in the presence of oil. This is especially true of lighter or less viscous oils, and the destabilizing effect is magnified with a higher salinity aqueous phase. PEF with a low salinity aqueous phase showed improvement in foam stability. The effective viscosities of PEF were higher than those of conventional foams with a high salinity aqueous phase and the presence of lighter oils. Further, PEF reduced the negative impact of oils on foam mobility. Of the surfactants studied, alpha olefin sulfonates were tolerant to high salinity brines as well as being compatible with polymer additives. Other surfactants, including amine oxide surfactants, were also studied and showed unusually high foam resistance and stability.

P. 277
Calculation of Minimum Miscibility Pressure
Authors: Wang Yun , Orr Franklin M.
Published: December 2007

We describe and test a method for calculation of minimum miscibility pressure (MMP) that makes use of an analytical theory for one-dimensional, dispersion-free flow of multicomponent mixtures. The theory shows that in a displacement of an oil by a gas with nc components, the behavior of the displacement is controlled by a sequence of nc-1 key tie lines. Besides the tie lines that extend through the initial oil and injection gas compositions, there are nc-3 tie lines, known as crossover tie lines, that can be found from a set of conditions that require the extensions of the appropriate tie lines to intersect each other. The MMP is calculated as the pressure at which one of the key tie lines becomes a critical tie line (a tie line of zero length that is tangent to the critical locus). We describe the numerical approach for solving the tie line intersection equations, and we use slim tube test and compositional simulation data reported in the literature to show that the proposed approach can be used to calculate MMP accurately for displacements with an arbitrary number of components present.

P. 313
Enhanced Recovery for Selected Components of a Highly Volatile Oil
Authors: Papp I. , Lakos B. , Palasthy S. , Tromboczky S.
Published: December 2007

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

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

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

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

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

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

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

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

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

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

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

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
Evaluation for Polymer Damage Aids in Candidate Selection for Removal Treatment
Authors: Carr Michelle A. , Yang B. Helena
Published: December 2007

Poor well performance due to permeability and conductivity damage can often be attributed to unbroken gel residue or inadequately reduced filtercake on formation faces. These forms of polymeric damage can negatively impact production rates by restricting the flow of oil or gas from the formation. Remedial treatments have been applied to wells exhibiting this type of damage using acids, oxidizers and enzymes. These removal treatments, when applied to accurately diagnosed polymer damaged wells and effective breaker systems are utilized, have shown to increase well production dramatically. However, polymer damage is only one of many factors that might be responsible for impeding optimum hydrocarbon flow. Therefore, the key to the success of a removal treatment is proper evaluation for polymeric damage when selecting a treatment candidate.

An improved flowback analysis has been recently introduced as a series of tests for polymer damage and for the evaluation of treatment load recovery. The testing procedures involved in that analysis can also be applied in candidate selection for remedial treatments and for monitoring the resulting clean up progress. Samples are analyzed before and after the treatment to determine total carbohydrate content, molecular weight distributions and the standard pH and viscosity measurements. The utilization of this improved analysis can assist in the selection of appropriate candidates and further direct treatment design. Several case histories on low performance wells are presented and include laboratory data to demonstrate candidate selection. Treatments with enzymes were used and detailed results are provided to evaluate the amount of polymer recovered. This paper also presents a guideline for use in the selection of candidates for remedial treatments.
History Matching and Modeling the CO-Foam Pilot Test at EVGSAU
Authors: Chang Shih-Hsien , Grigg Reid B.
Published: December 2007

A pilot area in the East Vacuum Grayburg-San Anders Unit (EVGSAU) was selected for a comprehensive evaluation of the use of foam for improving the effectiveness of a CO flood. The response from the foam field trial was very positive, it successfully demonstrated that field application of CO-foam is a technical viable process for improved oil recovery (IOR). A pseudo-miscible reservoir simulator, MASTER, which was recently modified by incorporating a newly developed foam model, was used to conduct a history match study on the pilot area at EVGSAU to understand the process mechanisms and sensitive parameters. The ultimate purpose was to establish a foam predictive model for CO- foam processes.

In this paper, the history match results are presented. The important modeling considerations that led to an acceptable history match are highlighted and discussed. Finally, the simulated results of a foam predictive ease are presented. The injection schedule of the foam predictive ease was specifically selected to mimic the filed injection schedule used in the foam pilot test at EVGSAU.

The simulated results are consistent with the field pilot test results. Overall, the foam model is found to be adequate for field scale CO-foam simulation. The results also confirm that the communication path between the foam injection well and the offending well had a strong impact on the production performance.

P. 365
Drill Pipe/Coiled Tubing Buckling Analysis in a Hole of Constant Curvature
Authors: Qui Weiyong , Miska Stefan , Volk Leonard
Published: December 2007

Lateral/multilateral drilling technique has significant potential to reduce well costs and increase hydrocarbon production. Coiled tubing drilling (CTD) takes a very substantial role in lateral/multilateral drilling. Well cost reduction in CTD can be achieved by transmitting weight to the bit effectively and preventing coiled tubing (CT) failure/fatigue and lock-up occurrence. To acquire this goal, an accurate buckling model becomes essential. This paper presents a new buckling model in a hole of constant curvature (such as the build section of a horizontal well). It starts from the formulation of the change in the strain energy of bending, the potential of the axial force and the potential of the radial force. Using the energy method, new equations are derived to predict the axial compression force to maintain stable sinusoidal configuration and the axial compression force required to produce helical configuration. Examples show that the axial compression loads to produce sinusoidal and helical forms are much larger than those in deviated wells, especially in short radius wells.

P. 385
An Integrated Study of Imbibition Waterflooding in the Naturally Fractured Spraberry
Authors: Guo B. , Schechter D.S. , Baker R.O.
Published: December 2007

In order to understand waterflood performance in low permeability, naturally fractured Spraberry Trend Area reservoirs, an integrated study of imbibition waterflooding has been performed. In this study, oil production during imbibition waterflooding in naturally fractured reservoirs has been mathematically analyzed on the basis of the rate law that governs mass transfer. Analytical models for decline curve analysis based on imbibition theory have been developed. Imbibition and capillary pressure experiments have been conducted in the laboratory using reservoir crude oil, synthetic reservoir brine, and low-permeability reservoir cores under room and reservoir conditions. Remarkable consistency has been observed using experimental data to scale-up and match reservoir performance. It is found that slow imbibition of water into the weakly water-wet rock matrix is the limiting step for oil recovery during waterflooding. This study suggests that better waterflooding should be sought in areas of high matrix permeability, high fracture intensity, and significant oil saturation.

P. 407
Simple Models of Water Imbibition and Gravitational Drainage of Oil in Rock Blocks
Authors: de Swaan Abraham
Published: December 2007

The oil outflow from porous-rock blocks due to water imbibition interchange and to gravitational drainage, are described by schematic mathematical models that include actual petrophysical properties of the fluids as well as dimensions of the blocks. The models were validated through comparison of their results with those of numerical simulations of these problems. The simulations cover wide realistic ranges of values of the properties involved.

The models can be used to compute the expected behavior of blocks in fractured reservoirs and to calibrate block behavior in numerical simulators that use parameters instead of actual properties of the fractured porous media.

P. 71
Novel Technology for Flame & Gas Detection in the Petrochemical Industry
Authors: Spector Yechiel , Jacobson Esther
Published: December 2007

A reliable and high performance novel method of Flame and Gas Optical Spectral Analysis (line of sight) was developed to meet the specific flame and gas detection needs of the petrochemical industry.

Petrochemical industries, especially the offshore and unmanned (unattended) areas in onshore refineries, pose a major safety hazard with respect to potential explosions and fire events. Unwanted fuel spills or fugitive flammable vapour clouds, migrating along congested pipe lines and hot production areas may cause upon ignition significant loss or damage. To help prevent events like the catastrophic fire that destroyed the offshore oil platform Piper Alpha in July 1988, a reliable and fast gas and flame detection system can be used to trigger effective risk management actions.

The present paper describes a patented method of Triple Optical Spectral Analysis employed for the detection of various gases in the air according to their unique "spectral finger print" absorption characteristics of radiation, as well as for analysis of emission and absorption radiation from combustion processes (hot CO2) for flame detection purpose.

The method has been applied in the development of unique gas and flame monitoring systems designed for "high risk - harsh/extreme weather conditions continuous operation" - These systems have been recently installed on several offshore platforms and oil rigs as well as on "Floating Production Storage and Offloading" - FPSO vessels.

The systems advantages and limitations as well as several installations and test data are presented. Various atmospheric conditions (direct and reflected sunlight, fog, rain, hail, snow) as well as false alarm stimulus (from radiation sources, flare stack, black body radiation, smoke, CO2 and atmospheric gases) are discussed.

P. 93
A Stage of Application Reservoir Management Process on Pantai Pakam Timur High Permeability Gas Field: A Field Case
Authors: Briantoro Cecep , Miftah Akhmand , Widjiono S.
Published: December 2007

The modem reservoir management process involves establishing a purpose or strategy and developing a plan, implementing and monitoring the plan, and evaluating the results. This paper present application of them on Pantai Pakam Timur gas field.

Pantai Pakam Timur is a new gas field in Pertamina Operasi Rantau Aset Pangkalansusu. This field located in the onshore portion of the North Sumatra Basin Indonesia. The Area is approximately 15 km North-West of Medan. The Pantai Pakam Timur Structure was discovered as gas and condensate entrapment in the major of Belumai formation (Z-238S,2400), Apart from that, there is Shallow prospect of Keutapang formation (Z-127S) is known brightly as "Strong reflection" in Seismic which about 1300 milli Sec.

Since the test production has just started about 9 years ago, it is very important evaluate the reservoir characteristics to obtain reliable data to set up the future field development strategy. The Pressure Transient testing of several wells show existing very difference of rock characteristic (the main is permeability) between deep zone (Z-238S,2400) and shallow zone (Z-127S), which on deep zone less than 5 Md, then on shallow zone (under discussion) the fantastic permeability had been found, they were greater than 500 MD from PPT-05A and PPT-06 wells.

The monitoring and evaluating are being performed through several technical approaches respectively, which are continuous monitoring on production performance, evaluating on well testing analysis and evaluating the P/Z versus Cumulative gas production plot, that is used by comparing toward Volumetric method, in line to Reserve estimation.

Furthermore the gas deliverability was conducted based on modified isochronal test results of several existing wells and appropriate Reserve to get more realistic and maximize the potential. (The strategy and developing stage).

P. 127
Advances in the Modeling of the Stratified Flow of Drilled Cuttings in High Horizontal Wells
Authors: Santana M. , Martins A.L. , Sales A.
Published: December 2007

The study of stratified solid liquid annular flows is of great interest of the petroleum engineering, specifically in the drilling area. This kind of flow describes the phenomena involved in the transport of the solids generated by the bit during the drilling of a horizontal or highly inclined well. In these operations there is tendency. due to the action of gravitational forces, of solids deposition in the lower part of the annular region formed by the wellbore walls and the drill column. One approach is the well known Two Layer Model, originally proposed by the mining industry to simulate the transport of solids at high concentrations in pipes. This model has been adapted to the problem of drilled cuttings transport, by the introduction of elements to model the non Newtonian behavior of the fluid and the annular geometry and is currently in use for design and troubleshooting in drilling operations. Some limitations of the model in the reprodttction of the role of rheology in the transport of solids motivated the formulation of more precise hypothesis. This paper deals with the analysis of the effect of the improvements in the final results of the model. Such improvements include the experimental determination of interfacial friction between the solids bed and the suspension. new criteria for solid liquid slip conditions and the choice of different rheological models.

P. 381
Techniques for Coping With Missing Data in Pressure Transient Tests
Authors: Aly A.M. , Bastian P.A. , Lee W.J.
Published: December 2007

This paper presents techniques we developed to cope with data missing from most of 72 buildup tests run between 1956 and 1986 in a large North American oil field. Most of the tests were run before the industry fully appreciated the need for early-time data and for measurement precision sufficient to generate useful derivative plots. Frequently missing were pre-test rates, time and flowing bottom-hole pressure at shut-in. We needed the buildup test analysis to help with reservoir description in an ongoing integrated study of the reservoirs in this field.

"Conventional" analysis suggested a large wellbore storage and skin factors of -4 to -5 in these unstimulated wells, assuming that the reported time and pressures at time zero were correct. Our work showed that missing only the first half-hour of the test can account for these anomalies. As a result, we developed guidelines for identifying invalid tests and for correcting erroneous interpretations in many of these tests to determine permeability and average pressure.

This paper helps the engineer to cope with missing data from field pressure tests and still be able to salvage the test and determine permeability and average pressure which are essential for reservoir characterization.

The technical contributions of this paper include criteria and techniques to cope with missing data in "old" field pressure tests; a procedure for obtaining useful permeability estimates and average drainage areas pressures from these tests; and guidelines for identifying tests that are simply invalid as reported because of incorrect shut-in times and missing initial shut-in pressures.

P. 389
Improved Selection of Candidates for Stimulation Treatment in the Wilcox Play in the South Texas/Mexico Border Area
Authors: Boonen P. , Byrd A. C. , Frisch G. , Kessler C. , Kubelka G. , Nixon Mark
Published: December 2007

A particular South Texas gas field has suffered severe production decline in the last two years. The wells were completed in the Wilcox formation, which extends from the Burgos Basin in Mexico through Texas into Louisiana. The object was to identify and treat potential producing zones in all existing wells to increase production. Hydraulic fracturing is the preferred stimulation technique in these formations. Typically multiple zones are fractured in each of the wells. The stimulation treatments are designed with the aid of 3D hydraulic fracture models. Wireline logs provide the most comprehensive and continuous input parameters in such modeling for borehole stress profile, permeability index, elastic moduli, lithology, porosity and fluid saturation's. Existing open-hole wireline logging data were reprocessed using a new technique which provides all the available logging data in a format suitable for direct input in 3D hydraulic fracture models. An automatic zoning technique divides the data into consistent intervals based on stress contrast. The representative design parameters are then computed for each zone. The outputs are a blocked stress profile and a set of zoned fracture design parameters.

This new technique was used to evaluate all the stimulation candidates in the field. One well was bypassed for treatment altogether, saving $500,000 to $700,000 on a stimulation that would have had a marginal result at best. In another well, the log was used in combination with a Fluid Efficiency Test (FET) and a Step Rate Test to show essentially no leak-off, and hence very low permeability in one zone. This lower sand was skipped, and upper zones were fractured to increase gas production from 550 MMCF/D to 1,300 MMCF/D.
Stimulation of a Low Permeability Natural Fractured Reservoir in the North-West German Carboniferous
Authors: Dietzel H.J. , Koehler M.
Published: December 2007

In this paper the development of a low-permeability natural fractured reservoir in the north-west German carboniferous is presented as a characterization of the reservoir its structural and facial properties are described including log and core analysis.

The reservoir consists of a series of tight sandstones separated by shales over a gas column of up to 900 m. As the natural fractures seem at least in parts to intersect the shale barriers, vertical interconnection of sandstone layers is probable. The permeability of the sandstones ranges from 0.01 md to 0.1 md at porosities from 3 % to 11 %. Thus, the production is nearly exclusively related to the natural fracture system. Wells without initial connection to the fracture system show only marginal or even no production after perforation. To get a link of the perforated intervals to the fracture system, hydraulic fracturing operations have been successfully applied~ Due to the poor prefrac rates, the data basis was insufficient for proper frac design. Based on the increasing experience of the preceding jobs a rough sizing of the amount of proppants to be placed gave the outlines for the frac design, which was then fine-tuned during an extensive data frac prior to the main frac. To overcome tortuosity and multiculture problems, proppant plugs were pumped during the data frac. In this paper frac-design, job description and post frac analysis of various frac operations are compared. The evaluation of transient pressure tests connected to the frac operations is presented. In conclusion the development strategy for this natural fractured reservoir, based on the increasing experience with successful hydraulic fracturing, is pointed out.

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Practical Production Data Analysis
Authors: Frantz J.H. , Spivey J.P. , Hopkins C.W.
Published: December 2007

This paper presents several production data analysis case histories. The primary purpose of this work is to illustrate the practical application of advanced production data analysis methods in low permeability gas reservoirs. Production data provide important information about reservoir quality and volume and the stimulation effectiveness. The analysis results can provide estimates for permeability-thickness product, skin factor or fracture half-length, gas in place, and drainage area. Pressure transient information can also be integrated with production data analysis to further characterize the reservoir.

Practical applications of production data analysis results include estimating short- and long-term production rates, estimating reserves, designing/evaluating stimulation (and restimulation) treatments, predicting and evaluating production increases from changes in flowing well pressure (plunger-lift and compressor installations), determining infill well potential and optimal well spacing, and identifying natural fracture and/or layered behavior. We will show examples of the above applications using actual field data. New type curves were also used in this work to analyze difficult datasets and to provide a starting point for more sophisticated history-matching methods. The final portion of this paper will include recommendations for field data collection and database utilization.

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The Relationship Between Fracture Treatment Shut-ins, Reservoir Permeability and Production Responses
Authors: Harkrider J.D. , Aud W.W. , Whittington J.O.
Published: December 2007

A basic search for geologists and engineers is to understand the flow potential from a reservoir. Though factors, such as reservoir pressure, net pay, reservoir heterogeneities and propped fracture lengths influence the well's productivity after completion, in-situ reservoir permeability dictates the relative magnitude of the production response. As such, in-situ permeability is a key variable for the economics of the well and future development opportunities. A method is presented that evaluates the pressure falloff response of fracture treatment pump-in tests for determining, on a negative basis, the reservoir permeability. A direct correlation is then made between the pump-in derived permeability value and the subsequent production response.

Conventional methods for determining reservoir permeability are often limited in the area of reservoir sampled. An alternative method is introduced that uses three-dimensional modeling of the pressure fall off responses to predict reservoir permeability. By using pump-in tests, communication with the formation is improved with a larger sampling of the reservoir area through the fracture face. This results in more of a macro permeability measurement as compared to other sampling methods. A comparative analysis between pump-in derived permeabilities and the associated production response provides a definitive measurement for developing a predictive reservoir permeability correlation.

This paper demonstrates the evaluation technique by presenting case studies in the Lewis, Almond, Frontier and Red Fork formations. The case studies show the relationship between the leakoff coefficient value, the pump-in derived reservoir permeability and the post-treatment production response. By relating these variables, a relative indicator of rock quality and flow capacity for a given reservoir can be determined during and immediately following the hydraulic fracture treatment. Given a statistically valid data set, the development of a permeability indicator provides the ability to predict production responses based on the pressure fall off observed while treating the well. Application of this technique may eventually lead to a reservoir/production tool that provides "real-time" go/no-go decision capabilities for geologists and engineers in completing multiple intervals in a well.

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Pressure-Dependent Leakoff in Fracturing Field Examples from the Haynesville Sand
Authors: Rollins K. , Hyden R.E.
Published: December 2007

This paper presents a field history of Haynesville Sand fracturing in which pressure-dependent leakoff has been encountered. Pressure-dependent leakoff has been identified and evaluated theoretically by others (Mukherjee et al.; Walsh, Warpinski, and Ayoub et al.). These examples are presented in a follow up of Barree and Mukherjee's paper in which simulation illustrates how 6-function plots can help detect pressure-dependent leakoff from pressure-fall off data.

6-function plots have helped describe the nature of a problem noted in some Haynesville Sand jobs in which bottomhole treating pressure was extremely sensitive to proppant concentration, often causing premature screenout. The screening technique has led to job modifications that allow successful completion of the stimulations. This paper summarizes one operator's ongoing experience with managing the job design to allow for fairly successful stimulation under these circumstances.

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