bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluation of Clay Stabilizers for a Sandstone Field in Central Saudi Arabia
Authors: Nasr-El-Din H.A. , Al-Mulhem A.A. , Lynn J.D. 
Published: December 2007

Abstract
An oil field in central Saudi Arabia produces super-light crude from a sandstone reservoir. The formation contains up to 2 wt. percent authigenic clays dominated by kaolinite and illite/montmorillonite mixed layer clays. To improve well productivity, a well stimulation treatment has been conducted on the producing wells in this field. The treatment introduces several fluids which might invade the formation and induce formation damage.
An experimental study was conducted to determine potential formation damage due to fines migration and clay swelling and design an effective clay stabilizer treatment. The work included performing coreflood experiments using reservoir cores at reservoir conditions (180 F and overburden pressure of 1500 psi). The critical salt concentration (defined as the salt concentration below which there is loss of permeability) was first determined. Several commercial clay stabilizers, cationic polymers, were evaluated. The effects of stabilizer concentration (0 to 2 vol. percent.), soaking time, and acids (15 wt. percent HCl) on core permeability were investigated in detail.
The experimental results indicated that the critical salt concentration (KCl brine) was nearly 5 wt. percent. Severe loss of permeability was observed when brines of lower salt concentrations were injected into reservoir cores. The effectiveness of clay stabilizer was found to be a function of chemical type and concentration. Some of the chemicals tested were not effective at concentrations less than 1.5 vol. percent. Others were effective clay stabilizers, but caused loss of injectivity at higher concentrations (2 vol. percent). After conducting a thorough investigation, it was found that these chemicals did not readily dissolve in water and formed fish- eyes. When these chemicals were injected into reservoir cores, they formed an external filter cake which caused loss of permeability. This problem was solved by good mixing of the stabilizer and proper filtration. Hydrochloric acid did improve the performance of at least of the clay stabilizers examined. Based on lab testing, a cost effective clay stabilizer was tested in the field at a concentration of 2 vol. percent. Field results indicated that the chemical did not cause loss of injectivity, and minimized formation damage due to fines migration and clay swelling.
P. 613
High Permeability Channels in Proppant Packs Containing Random Fibers
Authors: Howard P.R. , James S.G. , Milton-Tayler D. 
Published: December 2007

Abstract
This paper discusses laboratory studies to determine the nature of channel growth and stability in proppant packs with and without fibers. Tests were performed with proppant packs in three different types of experiments using natural sand and ceramic proppants, gas and water flow, and either perforations or an open proppant pack face. Proppant packs without fibers fail at low fluid velocities by the formation of voids at perforations or across the entire front of the proppant pack. Only when imperfect proppant packing was suspected did a channel form without fibers. Proppant packs with fibers form channels that are 2-10 cm wide depending on fluid velocity. The channel length increases in stepwise progression with increasing flow rate (velocity). The proppant pack on the either side of the channel supports the closure stress. Channels are stable over time at constant flow rate. Channels grew with fibers in all conditions tested. Random fibers mixed with the proppant extend the fluid velocity range for channel growth to much higher values.
P. 665
Designing a Remedial Acid Treatment for Gulf of Mexico Deepwater Turbidite Sands Containing Zeolite Cement
Authors: Rogers B.A. , Burk M.K. , Stonecipher S.A. 
Published: December 2007

Abstract
Ewing Bank 873 Field, developed from mid 1994 through 1995, produces from deepwater turbidite sands at an average depth of 11,000 TVD. Water depth at the platform is 775. In early 1996, pressure transient analysis of bottom hole pressure build-up surveys indicated increasing skins. Before pumping any type of remedial stimulation treatment, it was decided to test the recommended acid formulation in the lab. Acid corefloods were performed on composite samples from whole core using a typical 10% HCl/l .5% HF formulation. This acid formulation proved to be damaging as lab results indicated losses in permeability of up to 74%. A series of core floods were then performed on composite core samples to test the effects of various mud acid formulations, pre-flushes, post-flushes and acid additives. X-ray diffraction (XRD) and scanning electron microscope (SEM) analysis were also performed to help in determining the cause and mechanism of the damage. Results indicated that the loss in permeability was associated with acid additives which were causing fines migration and with silica gels precipitated as a result of the aggressive reaction of HCl with zeolite (clinoptilolite) within the formation. An optimum treatment formulation was identified, consisting of 10% Citric/1.5% HF acid, with no additives except corrosion inhibitor. This treatment was successfully applied in the field to five producing wells. Aggregate rate increased from 7400 BOPD to 16,000 BOPD and productivity index (PI) increased from 4.78 to 12.73 BOPD/psi of drawdown.
P. 693
Steam Oil Displacement and Vaporization of Minas Oil in Slimtubes
Authors: Benard J. H. , Richardson W. C. , Sitton G. M. 
Published: December 2007

Abstract
Steam displacement of oil in a slimtube under non-condensing isothermal conditions affords the opportunity to investigate two thermal mechanisms in relative isolation: steam oil displacement and steam distillation of oil in the dynamic situation. The added ability to investigate the composition of the produced oil under high resolution, allows estimation of a production allocation by mechanism. This work gives insights into strategies to accelerate the growth of the steamchest and enhanced compositional effects for improved steamflood performance.
The effects of temperature on oil and steam were determined in a sixty foot slimtube using Minas oil, a 33°API waxy oil from Indonesia, under isothermal conditions in the temperature range 300–600°F (149–315°C). Significant compositional changes in the hydrocarbon distribution of the produced oil allowed estimates that 16% of the oil is produced by vaporization alone in a light oil steamflood at 400°F (204°C). Higher temperatures increase the percentage for better vaporization and displacement recoveries. Steam can vaporize hydrocarbon components to at least C24 at 400°F (204°C) and much higher carbon numbers at higher temperatures. After steam breakthrough, vaporization becomes a major recovery mechanism in a steamflood. The vaporized hydrocarbons are normally seen as condensate in the field.
The steam vaporization process, like the carbon dioxide vaporization, removes the lightest hydrocarbons first and in boiling point order. The long slimtube acts like a gas chromatograph column and allows the separation of the hydrocarbons to be observed once vaporization begins. This is not normally seen in the field because the condensate commingles with the oil as it travels through the reservoir to the producing well. Therefore, a light oil having many light hydrocarbon components would produce a lot of condensate and a heavy oil could produce considerably less. The implications of compositional changes will be discussed.
The Extraction of Hydrocarbons from Crude Oil by High Pressure CO2
Authors: Siagian Ucok W.R. , Grigg Reid B. 
Published: December 2007

Abstract
This paper presents the results of a laboratory study investigation the capacity of CO2 to extract hydrocarbons from crude oils. The effects of pressure, temperature and oil composition on the extinction capacity of CO2 were studied. Extraction experiments using CO2 with Sulimar Queen stock tank oil and Spraberry sepetor oil samples at pressures between 1000 and 1900 psig were performed each at 95 F and 138 F. The experiments were performed by continuously injecting CO2 through 500-cc of oil placed in a 1.15 liter extraction vessel while continuously producing the upper or CO2 phase which contains the extraction products.
CO2 extraction capacity was found to be a strong function of pressure and temperature. The extract ion capacity increases with increasing pressure and decreases with increasing temperature. For the oils used in this study, the presence of solution gas in the oil does not affect the CO2 extraction capacity.
A CO2-Sulimar Queen oil extraction experiment at constant pressure and temperature of 1200 psig and 95 F, respectively, was performed for an extended period of time to determine the maximium oil recovery that can be achieved by CO2 extraction. It was found from the experiment that CO2 could recover at least 70 vol % or 64 wt % of the original oil in place. The CO2 extraction capacity decreased from around 0.3 g oil/g CO2 injected at the beginning of the extraction to 0.005 g oil/g CO2 injected at the time of termination.
Comparison of the extraction and slim tube tests results shows that the slim tube minimum miscibility pressures (MMPs) are near the pressure range at which a drastic increase in CO2-oil extraction rate occurs, which implies that CO2 extraction is a major factor in CO2-oil miscibility development. The comparison also shows that the extraction experiment appears to have promise as a good CO2-oil MMP estimation method.
P. 325
Engineering the Use of Green Plants to Reduce Produced Water Disposal Volume
Authors: Settle Troy , Mollock Gerald N. , Hinchman Ray , Negri M. Cristina 
Published: December 2007

Abstract
In 1990, the Laboratory began an investigation into biological approaches for the reduction of water produced from oil and gas wells. In the spring of 1995, the Company began an on-site experiment at an oil/gas lease in Oklahoma using one of these approaches. The process, known as phytoremediation, utilizes the ability of certain salt tolerant plants to draw the produced water through their roots, transpire the water from their leaves, and thereby reduce overall water disposal volumes and costs.
At the Company experimental site, produced water flows through a through where green plants (primarily cordgrass) have been planted in pea gravel. The produced water is drawn into the plant through its roots, evapotranspirates and deposits a salt residue on the plant leaves. The plant leaves are then harvested and used by a local rancher as cattle feed. The produced water is tested to assure it contains nothing harmful to cattle. In 1996, the Company set up another trough to compare evaporation rates using plants versus using an open container without plants. Data taken during all four seasons (water flow rate, temperature, pH, and conductivity) have shown that using plants to evapotranspirate produced water is safe, more cost effective than traditional methods and is environmentally sound.
P. 127
Petrophysical Properties Under True-Triaxial Stress For Hydrocarbon Recovery Prediction
Authors: Al-Harthy S.S. , Dennis J. , Jing X.D. , Marsden J.R. 
Published: December 2007

Abstract
The production of fluids from a reservoir often reduces pore pressure such that there is an increase in its effective stresses. During water flooding orgas injection the equilibrium rock stresses can also be altered in a similar dynamic manner. An understanding of these changes are of fundamental importance to performance prediction and management of the stress sensitive reservoirs.
Conventional laboratory methods for studying permeability under simulated burial conditions involve hydrostatic stresses, or sometimes anisotropic triaxial loading in which two of the principal stresses are equal. However, such conditions are rarely encountered in hydrocarbon reservoirs, and true-triaxial stresses are more representative. Whilst previous investigators have utilized true triaxial stresses on cylindrical and prismatic samples, such studies have been restricted by the limited deviatoric stress magnitudes which could be achieved with the test systems. In this investigation, laboratory equipment is being utilized to measure rock properties whilst applying the three principal boundary stresses independently using cubic samples. The apparatus uses closed-loop control, and can achieve deviatoric stresses in excess of 200 MPa and pore pressures to 70 Mpa.
This paper reports the experimental system and work which was carried out to examine the permeability hysteresis effect under hydrostatic, triaxial, and true triaxial stress conditions. The experimental data are being incorporated into a reservoir simulator to investigate the changes in hydrocarbon recovery under different stress conditions. The main objectives are to integrate important petrophysical properties such as permeability and porosity with rock mechanics, to investigate how permeability alteration under in situ stress conditions might affect hydrocarbon recovery.
P. 191
Errors in Input Data and the Effect on Well-Test Interpretation Results
Authors: Spivey J. P. , Pursell D. A. 
Published: December 2007

Abstract
Parameter estimation is one of the two principal functions of well test interpretation. Accurate parameter estimation depends on several factors, including correct reservoir model selection, sufficient test data within the flow regime(s) of interest, and accurate input data. The focus of this paper is the effects of errors in input data such as net pay, porosity, viscosity, formation volume factor, flow rate, and compressibility on the results of well test interpretation.
We consider two of the most commonly used reservoir models – a vertical well with wellbore storage and skin, and a finite-conductivity hydraulically fractured well. For the vertical well case, we allow for the presence of one or more boundaries, and for homogeneous or dual porosity behavior.
Many, if not all, of the observations offered in this paper are part of the working knowledge of the full-time well test analyst. However, these observations have not been systematically catalogued and discussed in the literature. The purpose of this paper is to provide just such a systematic catalog and discussion.
Using Reservoir Characterization Results at the Nash Draw Pool to Improve Completion
Authors: Stubbs Bruce A. , Murphy Mark B. , Hardage Bob A. , Martin F. David 
Published: December 2007

Abstract
The Nash Draw Pool (NDP) in southeast New Mexico is a cost-shared field demonstration project in the U.S. Department of Energy's Class III Program. A major goal of the Class III Program is to stimulate the use of advanced technologies to increase ultimate recovery from slope-basin clastic reservoirs. Advanced characterization techniques are being used at the NDP to develop reservoir management strategies for optimizing oil recovery from this reservoir.
Production at the Nash Draw Pool (NDP) is from the Brushy Canyon formation, a low-permeability turbidite reservoir in the Delaware Mountain Group. A major challenge in this marginal quality reservoir is to distinguish oil-productive pay intervals from water-saturated non-pay intervals. An advanced log analysis and interpretation program was developed that can be used to identify net pay in a complex reservoir. By properly identifying productive pay intervals, oil recovery from the Brushy Canyon reservoir is calculated to be 16.7%, rather than the 10% as initially estimated.
Interpretation and integration of recently acquired geological, geophysical, and engineering data revealed that the Brushy Canyon reservoir is much more complex than initially indicated by conventional geological analysis. A new reservoir description is being used to identify "sweet spots" for an aggressive development drilling program, and results of 3-D seismic data and other interpretations are being used for targeted drilling in high-grade areas of the Pool. Reservoir characterization has identified 17 additional vertical locations at the NDP. Due to cultural and potash mine constrictions, some of these wells will be accessible only with deviated/horizontal wells.
This paper presents recent results of an integrated reservoir characterization effort that is being used at the NDP to optimize reservoir management strategies. Because the reservoir is understood in detail, completion procedures and fracture stimulation treatments can be designed more efficiently. Marginal or non-economic zones are not completed which saves perforating, acidizing and fracturing a zone that will not produce enough reserves to return the cost of completion which results in more emphasis being applied to the zones that represent the most potential.
P. 219
More Effective Hydraulic Fracturing in Secondary, In-Fill Developments, Permian
Authors: Johnson Raymond L. , Rodgerson James L. 
Published: December 2007

Abstract
Hydraulic fracturing in the secondary recovery units in the Permian Basin of west Texas is often complicated by a number of factors. Generally, there exists a lack of historical data or information required to effectively design the desired treatment. Therefore, treatments in these fields have often been "cook-booked" and given less engineering attention due to their smaller size and scope. Many times the process is further complicated by the iterative nature required in effective treatment modeling (i.e., historical review, candidate selection, pre-job design, pre-job diagnostics, on-site or post-job modeling, and post-job diagnostics). In this paper, we will outline the steps required to improve these processes without expending excessive resources. Then, we will discuss steps where streamlining the process is warranted without compromising the end result, Finally, we will document and present several cases illustrating effective use of these technologies to obtain more accurate stress profiles and improved fracture treatments in secondary, in-fill development projects.
P. 281
Progressing Cavity Pump (PCP): New Performance Equations for Optimal Design
Authors: Samuel G. Robello , Saveth Ken 
Published: December 2007

Abstract
The drive for energy independence has created a window of opportunity to innovations in oil recovery. New artificial lift methods like progressing cavity pumping (PCP) have been successfully applied to downhole pumping applications. The unique progressing cavity feature has still to be explored fully to handle oil and gas efficiently without any practical problems. The multilobe pumps are also making inroads into the industry to be used under different operating conditions.
Although the design has been mainly based on empirical standards and trial and error modifications, a more phenomenally optimum design of the pump is required to achieve a high efficiency standard. This requires a more basic analytical consideration. Optimal relationship between the pitch and the diameter of the housing is obtained to achieve a maximum flowrate for multi lobe pumps. This makes it possible to design a power section of the pump with some degree of confidence and predict its performance characteristics with reasonable assurance. The practical usefulness of the theory, backed by the fundamental and optimal analysis for incompressible fluid, is demonstrated with numerical examples.
P. 313
Effect of Foam on CO2 Breakthrough: Is This Favorable to Oil Recovery?
Authors: Yaghoobi H. , Tsau J.S. , Grigg R.B. 
Published: December 2007

Abstract
Some surfactants that we tested were found to be more capable of selectively reducing gas mobility by a greater fraction in high- permeability sands. It is expected that foam can mitigate the problem of an early gas breakthrough in EOR processes. Laboratory experiments were conducted to examine the effect of foam on two different systems of porous media with various fluid saturations. The first system was a fired Berea sandstone core with relatively homogeneous permeability. To simulate reservoir heterogeneity, the second system was a composite core of coaxial permeability (high and low) layers in capillary contact. Experiments were conducted in these systems by injecting CO, CO/brine, or CO/foam into core with different fluid saturations (brine, surfactant solution, and oil). The breakthrough time and incremental fluid recovery were recorded and compared. This study indicates that foam could delay CO breakthrough time and improve oil recovery efficiency in both single and composite cores. The experimental results of the composite core tests also shows a significant improvement in oil recovery from the low permeability region, when CO/foam was used.
P. 337
Understanding and Exploiting Four-Phase Flow in Low-Temperature CO2 Floods
Authors: Grigg Reid B. , Siagian Ucok W. R. 
Published: December 2007

Abstract
This paper reviews the effect of multiphase flow on mobility control in CO2 flooding of oil reservoirs. It then presents experimental data on Sulimar Queen reservoir oil and CO2 injection. Swelling tests for CO2 and oil are perform in a visual PVT cell to identify saturation points and non-aqueous two and three phase regions. Slim tube tests used to determine the minimum miscibility pressure (MMP) at three temperatures (78°F, 95°F, and 138°F) are presented. The slim tube tests are also used to show temperature and pressure effects on the development of miscibility.
Prediction of Turbulent Friction in Rod Pumped Wells
Authors: Xu J. , Shirazi S.A. , Doty D.R. , Schmidt Z. , Blais R.N. 
Published: December 2007

Abstract
Frictional forces acting on the rod caused by the rod reciprocating in the flowing fluid significantly affect the prediction and diagnosis of rod-pumping system performance. Available studies of the flow in the tubing combined with moving rods and couplings are limited to laminar flow. The flow is more likely to be turbulent, however, for liquids with low viscosity and for regions near the rod couplings. Therefore in the current study, turbulent flow in the annular region between the stationary tubing wall and the moving rod/coupling is considered.
Computational fluid dynamics (CFD) is employed to simulate turbulent flow in the annular region with moving rods and couplings. Also, a simplified model using a mixing-length method is developed that is much more computationally efficient than the CFD code. The CFD code employing the standard k-model is used to predict turbulent fiction factors in the annulus with the moving rods and couplings. The simplified model is developed to predict turbulent fiction factors in the annulus with the moving rods. The results from these models are compared each other and with the available data published. In addition, the friction factors between the rod/coupling and fluid can be represented in terms of four parameters: the rod to tubing radius ratio, the coupling to tubing radius ratio, the fluid Reynolds number, and the relative rod velocity.
P. 397