bluuebunny/crossref_metadata_2025_split huggingface dataset:
Maximum Allowable Production Rates from Openhole Horizontal Wells
Authors: El-Sayed A-A. H. 
Published: December 2007

ABSTRACT
The completion technology for horizontal wells presents numerous design possibilities. The simplest and least expensive method is completing the well as open hole or using slotted liners. The majority of producing horizontal wells are being completed as open hole; this technique offers large flow areas, much more than when cemented and perforated casing is used. But hole stability and pressure drawdown may cause hole collapse and sand production which will restrict the production rate. The problem then is to determine the maximum allowable production rates from horizontal wells completed as open hole.
This paper discusses the stress distribution around a horizontal borehole function of the amount of pressure drawdown and the overburden loads, and the stability of this hole under these stresses. It also assesses the production rate at which sand grains may be produced with the fluid. The paper presents an equation to calculate the maximum production rates from open hole completed horizontal wells without sand problems or hole collapse. The equation includes the effect of well depth and the length of the horizontal displacement. Also, it can be used to calculate the effective borehole diameter of the horizontal well that minimizes sand production.
Subsurface Stratigraphy, Depositional History, and Reservoir Development of the Early-to-Late Permian Unayzah Formation in Central Saudi Arabia
Authors: Ferguson G. S. , Chambers T. M. 
Published: December 2007

ABSTRACT
Six oil and gas fields have been discovered in Permian strata in central Arabia since June of 1989. The majority of reserves are contained within the Unayzah Formation, a siliciclastic succession of fluvial, coastal plain, deltaic, and shallow marine facies, ranging in age from Early to Late Permian. Distribution of Unayzah facies is controlled by paleotopography on the Hercynian Unconformity, sea-level fluxuations, and both local and regional structure. The Unayzah C member records the first post-Hercynian marine incursion. The Unayzah A and B members record a second transgressive-regressive cycle. A final Permian transgression caps the Unayzah Formation.
A complex interplay of structurally and sea-level controlled facies trends, coupled with erosion during sea-level lowstands, has resulted in the development of a variety of reservoir types. Six different reservoir facies have been identified: Unayzah B member braided river sandstones; shoreface/foreshore, delta channel, and coastal plain channel sandstones of the Unayzah A; and valley fill channel and transgressive lag sandstones deposited during the Khuff transgression. Each reservoir type is characterized by different reservoir attributes.
In addition to proven reservoir types, significant potential exists for stratigraphic trap development along depositional boundaries of the Unayzah A and B members against the Central Arabian Arch.
Determination of Fracture Volume and Closure Pressure From Pump-ln/Flowback Tests
Authors: Soliman M. Y. , Daneshy A. A. 
Published: December 2007

ABSTRACT
A technique based on a simple compressibility equation and a mass balance equation has been developed that allows accurate determination of fracture volume and closure pressure. This new technique may help resolve the controversial determination of when a fracture closes. Through the graphical representation of this technique, knowledge of the fracture closure mechanism has been gained and presented in this paper.
The presented technique may be applied to either microfracture or minifracture tests. It may be applied to a pump-in/flowback test (microfracture) or be coupled with the conventional minifracture analysis technique for application to pump-in/shut-in tests.
The new technique is illustrated in this paper through its application to actual field cases. In the first field case, it is applied to a microfracture test (pump-in/flowback) performed on a shale formation. The technique clearly identified the closure pressure of the fracture and the fracture volume, and fluid efficiency was calculated using an iterative scheme. In the second example, the technique was applied to a minifracture test (pump-in/shut-in).
The chief technical contributions of this paper may be summarized as follows:
A simple new technique is presented for determining fracture volume and closure pressure. Through the graphical representation and application of the new technique, a better understanding of the closure mechanism has been achieved. This technique determines fracture closure pressure with a fairly high degree of certainty.
A Laboratory Study of CO2-Foam Process for Bati Raman Field, Turkey
Authors: Alkan H. , Goktekin A. , Satman A. 
Published: December 2007

ABSTRACT
An immicible CO2 project has been continuing in Bati Raman field, Turkey. Field results indicated the early breaktrough of CO2 in most of production wells due to heavy oil content and fractured structure of the limestone reservoir. A laboratory study was conducted to investigate different aspects of the feasibility of in-situ foaming to improve mobility ratio and injection profile in Bati Raman reservoir.
Well-known static screening tests were used to select the most suitable surfactants at atmospheric pressure. These tests together with high pressure static tests using synthetic reservoir brine showed better stability for 3 ethoxylated surfactants. To determine the retention properties of these surfactants static and dynamic experiments were performed. The effects of pH, flow rate and fractured structure of the reservoir rock on retention were also investigated. Higher surfactant losses resulted in partionning experiments.
To justify the results of static foam tests and to investigate some dynamic parameters on gas mobility, dynamic tests across the sandstones and carbonate Bati Raman cores were carried out. Artificially fractured Bati Raman cores were utilized to better simulate the heterogeneity of the reservoir.
A New Through-Tubing Oil-Saturation Measurement System
Authors: Roscoe B. A. , Stoller C. , Adolph R. A. , Boutemy Y. , Cheeseborough III J. C. , Hall J. S. , McKeon D. C. , Pittman D. , Seeman B. , Thomas S. R. 
Published: December 2007

ABSTRACT
Carbon-oxygen logging is used primarily to estimate oil saturation in cased-hole conditions when the formation water is fresh or unknown. The drawbacks of current techniques are: 1) slow logging speed, 2) large tool diameter, and 3) excessive sensitivity to borehole fluid composition. A new, slim, neutron-induced gamma ray spectroscopy logging system has been developed to overcome some of these limitations. The new logging service is called the Reservoir Saturation (RST*) Tool. Initial field tests are being carried out in the Middle East.
The RST tool uses multiple detectors to separate the signal contributions from the borehole and the formation. Therefore, even when the borehole fluid composition is unknown, oil saturation can be determined in addition to the borehole oil fraction. This presents the possibility of logging flowing wells, which ensures that reinvasion and crossflow will not affect the results, and eliminates the costs of well preparation.
A reduction in sonde diameter, without sacrificing logging speed, has been made possible through the use of specially developed technologies in the areas of scintillation materials; photomultiplier tubes; pulsed neutron generators; pulse acquisition circuits; and high-density, digital, signal-processing electronics. The new tool fits through production tubing and operates at temperatures to 150 C. Since no Dewar flasks are used, there is no limit on how long the tool can stay in the well.
Improved Method of Compositional Analysis of Liquid at High-Pressure Condition in PVT Study of Gas Condensate
Authors: Khan M. S. , Hatamian H. 
Published: December 2007

Abstract
A new technique of direct sampling system is designed to analyze the liquid and gas phases at high pressure condition ranging from 10 to 1000 bars from the PVT cell at a maximum temperature of 300° F. The sampling and its analysis can be made during constant composition expansion and constant volume depletion experiments at each pressure step. Study of the phase behaviour of synthetic mixtures of hydrocarbon are carried out and the technique is used for the analysis of liquid and gas phases from the PVT cell at equilibrium conditions. The important application of this technique is the analyses of the liquid from the PVT cell after each step during depletion experiment. The existing method uses mass balance equations to calculate liquid composition in the cell at each depletion step. By using this method, negative masses of lighter hydrocarbons are reported in PVT studies of gas condensate. To avoid this error in the calculation of the liquid composition, this new technique is developed and validated. Production from gas condensate reservoir by depletion causes liquid dropout in the pore space as a result of retrograde phenomenon. A proper knowledge of phase behaviour is essential in order to plan and devise a suitable schem for the recovery of this fluid. To simulate depletion mechanism, constant volume depletion experiment is conducted in the laboratory. Since phase behaviour is dependent on the reservoir conditions and composition of the reservoir fluid, accurate compositional analysis of liquid is very important in characterizing the behaviour of gas condensates.
Evaluation of Closed Fracture Acidizing Performed in a Tight Limestone Formation
Authors: Sizer J. P. , Moullem A. S. , Abou-Sayed I. S. 
Published: December 2007

ABSTRACT
The stimulation potential of a tight "chalky" formation using closed fracture acidizing was successfully demonstrated. The stimulation consisted of a pad-acid treatment followed by a closed fracture acidizing stage. The step-rate injection test with seawater established a fracture gradient of 0.71 psi/ft (16.1 kPa/m). The high leak-off coefficient calculated from the mini-frac was primarily attributed to the matrix acid job prior to the frac. Temperature surveys run following the main frac indicated an exposed fracture height of 70 ft (21m). Pressure transient testing indicated an etched fracture half length of 200 ft (61m). Additional production enhancement methods, pressure maintenance, gas lift, etc., may be necessary to maintain the high production potential of the stimulated reservoir. The wellbore tubular goods were also found to greatly impact well stimulation and production mechanism. Further stimulation testing in this field is recommended to fully evaluate the best field exploitation technique.
Improving the Productivity of Khuff Gas Wells in Bahrain Field
Authors: Janahi I. A. , Mirza M. S. 
Published: December 2007

ABSTRACT
The Khuff gas is the main source of energy in the State Of Bahrain. The production from Khuff reservoir was started in 1969 when the country decided to embark into a major industrialization program. Since that time, 20 wells were drilled and completed in the Khuff zones and all these wells have been producing smoothly and without any major mechanical failure.
Recently, the later stage wells which are mostly in peripheral locations have exhibited some problems like relatively low deliverability compared to other Khuff wells, high H2S production and downhole scaling problems.
This paper discusses the recently detected problems and suggests remedial work. Also, it proposes modifications in the current completion of Khuff wells specifically the completion design, completion fluid, sequence of perforation, testing and stimulation of the producing zones.
A Synergistic Approach to Characterization of Reservoir Permeability: A Conditional Kriging Method
Authors: Al Rumhy M. H. , Archer J. S. , Daltaban S. T. 
Published: December 2007

ABSTRACT
The geostatistical method of kriging, conditioned with geological information, has been used to indicate potential methods for characterising permeability of reservoir domains. In this method, the hard permeability data (eg. core data) obtained from drilled wells needs to be supplemented with "soft" data between wells. This paper examines the way in which soft data may be inferred from statistical distributions and how geological controls are used to develop soft data for enhancing the hard data.
A minipermeameter was used to develop examples of permeability data at different scales. Data from outcrops and in the laboratory on rock slabs were used for the evaluation of geostatistical methods for representation of permeability. Monte Carlo methods were also used to generate data of different statistical realizations to mimic some probability distribution functions of permeability which might derive from different depositional environments.
This study has demonstrated how use of geological controlled soft permeability representation from appropriate data sets leads to improved reservoir simulation models and performance prediction. It has also shown that compared to the conventional geostatistical method of kriging, the ‘conditional kriging’ approach is much superior.
Review on the National and Regional Response to Oil Spill in the Arabian Gulf
Authors: Fakhro K. M. 
Published: December 2007

ABSTRACT
Over the past decades, the oil industry has grown enormously, resulting in a considerable number of island's oil and gas fields being fully developed.
The offshore activities have been boosted more as inland areas been fully exploited to meet the increasing world's demand on Oil. This increase in offshore activities has resulted in enormous quantities of petroleum and its products being transported by sea around the globe everyday posing more threat to the Marine Environment.
Over 30% of all oil carried by ships is produced in this region. It is exported through a narrow bottle-neck passage, "Straight of Hormuz" creating a continuous heavy traffic that increases the daily risk potential for ships collision, grounding or explosion that threaten the marine environment and the economy of the coastal states, should a major oil spill occured anytime. The paper reviews some major spills in the area and the action taken by the responsible authorities.
The high risk potential of pollution by oil or any other harmful substances in the Arabian Gulf always exists and the need for a competent national and regional bodies was felt necessary to co-ordinate efforts in combating or mitigating marine oil pollution. The paper reviews and discusses the status of such bodies and concludes with an emphasis on strengthening them.
Lithology Determination of Clastic Reservoir Facies from Well Logs, Saudi Arabia
Authors: Al-Sabti H. M. 
Published: December 2007

ABSTRACT
A method was developed for predicting lithology from well logs for the Mauddud, Safaniya, and Khafji Members of the Wasia Formation in Safaniya, Zuluf, Marjan and Maharah Fields of offshore Saudi Arabia. A group of electrofacies (i.e. litho-facies or lithofacies groups that exhibit a unique set of well log responses, H.T. Abbott, 1982), were defined using gamma ray, density, sonic, calculated shale volume and caliper-log data. The eight basic rock types represented by the electrofacies are limestone, argillaceous limestone, sandstone, argillaceous sandstone, shale, ironstone, iron-rich sandstone and iron-rich shale.
A FORTRAN program was written to identify these electrofacies. The program output consists of a series of intervals that are defined by a Top and Base depth and an electrofacies code. These numerical data were compiled into a lithology database. A comparison of this information with 6,705 feet of core from 12 wells resulted in an accuracy rate of approximately 97 percent.
Applications for these data are varied and range from use in Saudi Aramco's ZYC0R (STRATVIEW), INTERGRAPH (G.I.P.S.I.E.) and SIERRA cross section display programs to input for three-dimensional geological modeling. The use of electrofacies in reservoir characterization will enable geologists and engineers to better understand and predict the impact of lithologic variation on reservoir performance.
The DOE Gladys McCall Geopressure-Geothermal Gas/Brine Well Test: Summary of Well Test Results
Authors: Rogers L. A. , Randolph P. L. , Hayden C. G. , Eaton B. A. , Meahl T. E. 
Published: December 2007

Abstract
The U.S. Department of Energy (DOE) Gladys McCall well in Cameron Parish, Louisiana, was drilled in 1981 and subsequently tested as part of the DOE Geopressured-Geothermal Energy Program. The well produced geo-pressured brine containing dissolved natural gas from the Lower Miocene sands at a depth of 15,150 to 16,650 feet (4 618 to 5 075 m). More than 25 million barrels of brine (4 (E+06) m3) and 727 million standard cubic feet of natural gas (20.6 (E+06) m3) were produced in a series of flow tests between December 1982 and October 1987 at various brine flow rates up to 28,000 barrels per day (4 452 m3/d). Short-term flow tests for the Number 9 Sand found the size of the reservoir to be too small for long-term production, so it was plugged off. Initial short-term flow tests of the Number 8 Sand found a suitably large reservoir with a permeability of 113 to 132 millidarcies (md) (111 to 130 (E-03) μm2) and an indicated volume of 430 to 550 million barrels of brine (68.4 to 87.5 (E+06) m3). The long-term flow and buildup test found that the reservoir was much larger than was measured by the short-term flow test. Test data and numerical simulation of the flow and buildup tests through 1990 required the initial reservoir volume, as measured by the short-term tests, to be connected to additional reservoir volume with lower permeability. A total reservoir volume of about 7.8 billion barrels (1.2 (E+09) m3) was determined with an effective permeability of the distal parts of the reservoir in the range of 0.2 to 20 md (0.2 to 20 (E-03) μm2). Detailed chemical analysis of the brine and gas found the brine to be slightly undersaturated with gas at about 29 SCF/STB (5.16 m3/m3). The produced gas/brine ratio was invariant with production time and flow rate. Calcium carbonate scale formation in the well tubing and separator equipment was controlled by the injection of a scale inhibitor into the flow line and by twice successfully injecting inhibitor "pills" directly into the reservoir. Corrosion and/or erosion of piping and equipment was also significant.
Measurement of Coal Cleat Porosity and Relative Permeability Characteristics
Authors: Puri R. , Evanoff J. C. , Brugler M. L. 
Published: December 2007

Abstract
After several trials and errors, an acceptable procedure has been formulated for cutting, handling, preparing, and selecting coal core samples for laboratory tests. The unsteady-state method for relative permeability measurement has been found to provide satisfactory results when applied to whole core samples of coal. Furthermore, a novel nondestructive and simple laboratory technique has been developed to estimate the porosity and irreducible water saturation associated with the coal cleat network. In this paper, examples are presented using results obtained with coal core samples from the San Juan and Warrior Basin. Laboratory measured relative permeability curves, porosity, and irreducible water saturation of coal cleats have proven valuable in numerical simulation and other engineering studies of coalbed methane recovery.
Analysis of Well Test Results From Horizontal Gas Shale Wells
Authors: Salamy S. P. , Aminian K. , Koperna G. J. , Locke C. D. 
Published: December 2007

ABSTRACT
Recent drilling and completion operations have demonstrated the technical and economical successes of horizontal wells over that of vertical wells. The need for horizontal wells was established as a vital production enhancement technique for wells producing from economically marginal, low permeable gas formations in the Appalachian Basin exhibiting strong permeability anisotropy.
As part of a U.S. Department of Energy (U.S.DOE) funded research project, several horizontal wells were drilled and completed to the Devonian Shale strata in the Appalachian Basin. Production from these wells exhibited high improvement ratios to that from vertical wells; however, to enhance the economics of the horizontal wells, stimulation was indicated. The success of the stimulation techniques and the measure of improvements were determined from production results and/or pressure analyses.
This paper exhibits and summarizes the results of production and pressure buildup data analyses for the different horizontal wells. Based on pre- and post-stimulation production and pressure data, various well test analysis techniques such as type curves for horizontal gas wells, reservoir simulation, Horner’s method, and other applicable techniques are utilized.
Finally, the correlation of production and pressure analysis results helped in the assessment and evaluation of the stimulation techniques.
Estimating the Recovery from an Average Well in a Tight Gas Formation
Authors: Holditch S. A. , Lin Z-S. , Spivey J. P. 
Published: December 2007

Abstract
Many tight gas formations consist of numerous reservoir layers that are dispersed both vertically and laterally in a thick, complex sand dispersal system. A typical well will encounter layers of sandstone, siltstone, and shale. Depending upon the depositional and diagenetic history of the formation, these different layers of sandstone and siltstone can have significantly different values of permeability, porosity, and gas saturation. In many formations, like the Travis Peak in east Texas, the Wilcox in south Texas, the Frontier in Wyoming, or the Mesa Verde in Colorado, a well can encounter over one thousand feet of sandstone layers that contain gas. These complex reservoirs can be very difficult to produce because of low permeability and poor lateral continuity of the productive layers.
In these complex reservoir systems, one needs to be able to forecast both flow rates and ultimate gas recoveries to properly predict the economics of developing the formation. An engineer must evaluate existing wells to obtain a distribution of reservoir properties. This distribution of reservoir properties, if properly interpreted, can be used to predict well performance and compute the economics of drilling additional wells in a particular geographic area.
The knowledge of how reservoir properties are distributed is very important to the petroleum engineer. The most important properties are formation permeability, formation porosity, net pay thickness, and the areal size and distribution of the sandstone units. Once the distribution of these properties is known, one can determine the proper method of averaging these properties so that one can accurately predict the performance of additional wells drilled to this formation.
The Effect of Permeability Anisotropy on the Evaluation and Design of Hydraulic Fracture Treatments and Well Performance
Authors: Gatens J. M. , Lee W. J. , Hopkins C. W. , Lancaster D. E. 
Published: December 2007

ABSTRACT
Horizontal permeability anisotropy can significantly affect the performance of wells stimulated with vertical hydraulic fractures in low permeability reservoirs. The purpose of this paper is to demonstrate, using simulated and actual data, the effect permeability anisotropy can have on the apparent fracture half-length calculated from well test data, on well performance, and on optimal fracture treatment design.
For example, in a well with a horizontal permeability anisotropy ratio of 20:1 and a 500 ft propped hydraulic fracture (oriented in the same direction as the largest component of horizontal permeability), the apparent fracture half-length calculated from a conventional well test would be about 240 ft. If anisotropy can be identified and quantified, this information can be used to modify the design of stimulation treatments, to compute more realistic estimates of fracture half-length and long-term well performance, and to modify development well spacing patterns.
Examples are presented using simulated and field data.