bluuebunny/crossref_metadata_2025 huggingface dataset:
In Situ Formation Wettability Determination in Depleted Zones
Authors: Desbrandes Robert , Bassiouni Zaki , Gualdron Jorge
Published: December 2007

Most rocks ore normally water-wet. However, If the rock has been in contact with crude oil, the coating of the grains with asphaltenes and resins may change the wettability from water- to oil-wet. This change cannot be overlooked since wettability affects such properties as capillary pressure, relative permeability, and electrical resistivity. Besides its effect on formation properties, wettability plays an important role in recovery mechanisms.

The technique developed previously for in situ wettability determination at the oil-water contact level has been extended to the movable oil-residual oil contact level. Some formations contain a residual oil saturation below the movable oil level due either to a gradual escape of the hydrocarbons through the upper confining layer during geological time, or to efficient water encroachment.

Experiments conducted in a water-wet sand pack have shown that, in the residual oil zone, the water pressure gradient is recorded up to the movable oil level where it changes to the oil gradient. The free water level is located below the gradient change and can be determined at the intersection of the oil and water gradients.

In an oil-wet sand pack initially saturated with oil, the experiments show the pressure gradient changing from the water gradient to the oil gradient at the movable water level, which is located below the free water level. The shape of the pressure profile can be used to qualify wettability. The pressure data can also quantify wettability using the J-function method.

Wettability determination in situ is possible with a formation pressure profile recorded with a wireline formation tester. An example is shown in which the contact angle is calculated.

Formation pressure profiles recorded in the oil-water transition zone in wells with a residual oil saturation yield information on the wettability of the formation and the position of the movable oil level.
A Generalized Model for Formation Damage by Rock-Fluid Interactions and Particulate Processes
Authors: Civan Faruk
Published: December 2007

This paper presents an analysis, discussion, and formulation of fundamental processes which cause formation damage in geological porous media.
Development of Flexible Pipe for Sour Fluid Service
Authors: Fuku Tadashi , Goto Yasuhiro , Yamaguchi Takumi , Ishii Kenichi
Published: December 2007

Flexible pipes used in offshore oil production 1, 2, 3 are kept watertight by a plastic sheath, with the result that their reinforcement steel never comes in contact with the fluid that is transported in them.

But since various gas components permeate the plastic layer, there is some concern that the hydrogen sulfide in a sour environment could cause sulfide stress corrosion cracking (SSCC) or hydrogen induced cracking (HIC).

By special processing and heat treatment we have developed steel wire having a fine spheroidized structure, and in SSCC and HIC withstand tests we have confirmed that no cracking occurs even after bending and welding.

Satisfactory test results have been obtained with flexible pipe made from this material.
Formation Evaluation of a Horizontal Well
Authors: Najia W. K. , Habib K. H. , Asada J.
Published: December 2007

In Upper Zakum Field, the interest in horizontal drilling has continued. A second horizontal well was drilled during the second half of 1989. This necessitated running logging tools for well control and to evaluate the reservoir characteristics. The logging tool selected for this well is that of Sperry-Sun. Tools configuration and tolerance were found to fulfil ZADCO's requirements and specifications.

The services provided included Measurement While Drilling (MWD) directional services and RLL (Recorded Lithology Logging). The RLL services cover Dual Gamma Ray (DGR), Electromagnetic Wave Resistivity (EWR) and Compensated Neutron Porosity (CN porosity). All the RLL tools were an integrated part of the Bottom Hole Drilling Assembly. Data acquired while surveying was recorded in a recording sub down-hole and retrieved when the tools were up at the surface.

A PC assisted quick look interpretation was carried out using Archie's equation in shale free limestone to calculate:

Effective porosity Water Saturation and Bulk water volume.

Reservoir characteristics as derived from the RLL were compared with near-by wells and geological maps and were found compatible with the in-use Geological/Reservoir model.
Approach to Emergency Pipeline Repair System
Authors: Binthabet Hussain A. , El-Shenawy Maamoun
Published: December 2007

ADMA-OPCO has main subsea pipelines in sizes ranging from 16" to 48" Dia with approximately total length of 275 km through which crude oil, gas and condensate are transmitted from Umm Shaif and Zakum Fields to Das Island, north west of Abu Dhabi, for processing and loading.

These pipelines are vital, considered the nerve system of ADMA-OPCO production facilities and are the only source of gas supply to ADGAS' LNG plant. Hence their availability and reliability is the prime factor in ADMA-OPCO's and ADGAS' productivity.

Having noted that recently Abu Dhabi offshore areas have had quite an increasing number of reported pipeline incidents, the possibility of a pipeline failure resulting from seafaring traffic, operation and materials can never be ruled out Such failure can lead to prolong production down-time especially if an operator is not adequately equipped to cope with such an emergency failure.
Digital Control Systems for Oilfield Operations
Authors: Heraiba F. A.
Published: December 2007

Development of UPPER ZAKUM Field entails the use of an advanced computerised control system. The system comprises SCADA; Distributed Control System (DCS) and Programmable Logic Controllers (PLC).

The system provide the operators with an efficient and flexible tool for remote and automated operations; featuring economical cost, reliable control and better operating performance.

After arranging in depth training for the operational and maintenance groups, the operating personnel accepted the system and continued to operate it efficiently.
Development of the Naturally Faculted ISND Shuaiba Reservoir
Authors: Buksh G.
Published: December 2007

This paper describes the Idd el Shargi North Dome (ISND) reservoir located offshore Qatar. Production performance of this carbonate oil reservoir, intensely faulted in the crestal area, is summarised.

A phased development plan of the reservoir is presented, which consists of gas/oil gravity drainage in the crest and pattern water flooding in the flanks.
AVO Techniques for Carbonate Reservoir Characterization
Authors: Poster C. K. , Buchan I. C.
Published: December 2007

AVO (Amplitude-vs-Offset) is a seismic technique which examines how reflection events change with varying angles of incidence of the seismic waves. This change is related to elastic properties of the reflecting formation, which may be associated with particular fluid saturation and lithology conditions.

In this paper, a data set composed of well logs and a coinciding surface seismic line are used to evaluate the AVO technique for a major Gulf carbonate reservoir. From the logs, Poisson's ratios were calculated and combined with a log-based stratigraphic model to estimate the AVO response of the reservoir formations. Specifically, the amplitude gradient curve for a zero phase response with increasing angle was calculated. The surface seismic data was processed for a comparable AVO result. Combined interpretation of the two indicates possible changes in the oil reservoir across a structure. One conclusion is that AVO interpretation without reference to valid physical models is very difficult.
Maximum Allowable Production Rates from Openhole Horizontal Wells
Authors: El-Sayed A-A. H.
Published: December 2007

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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.
Gas Research Institute Program in Natural Gas Processing
Authors: Leppin D. , Meyer H. S.
Published: December 2007

The Gas Research Institute (GRI) has begun an R&D Program directed towards natural gas processing issues. Of particular interest is research on problems connected with small-scale subquality natural gas processing. Both fundamental, knowledge-building and applied research are carried out.

Studies of the resource base were undertaken in order to focus the program on those areas of greatest importance. The size of the total resource was estimated at 600 TCF (17 Tm3), of which approximately 40% had significant H, S, COy or K2 contamination. The size of the present and estimates of the future Lower-48 gas processing industry was then developed based on the resource estimates and other factors. An engineering and construction firm, M.W. Kellogg Company, was contracted with to provide a suite of designs/cost estimates for representative industry standard small-scale plants to serve as a baseline with which to evaluate new technology against These results are expected to be available early in 1991. Major findings of the - studies so far are an unexpectedly large regime of economic viability for hybrid systems of amines with membranes for CO2 removal. Two major field activities were started - testing of cellulose acetate membranes for CO2 removal with simultaneous dehydration, and testing of the Su£Ferox liquid redox process for sulfur recovery.
The Low-Volume Flowmeter: Gas Flow Measurement to the 10th of an MCF From Low-Volume Entries
Authors: Walbe K. A. , Collart D.
Published: December 2007

Locating and measuring low volume gas entries is a critical problem in many Devonian Shale wells in the Appalachian Basin, since many of the small gas entries are below the resolution of conventional geophysical logging tools.

The Low Volume / High Resolution Flowmeter (HRFM) is an extremely sensitive flow measurement tool consisting of three basic parts. The lowest part of the tool contains the sensor section which is comprised of a pressure transducer and a tracer gas reservoir positioned below a tracer gas detector; the central section contains the gamma ray detector for lithology correlation in both open and cased holes; and the upper part of the tool contains the casing collar locator for cased hole referencing.

Flowrate is determined by injecting a tracer gas into the gas flow. The dilution of the tracer gas is then measured at a downstream detector. The mass flow is therefore determined by this method ratherthan the velocity of the gas in the wellbore as measured by conventional production logging spinner surveys. Therefore, the HRFM can measure a full spectrum of flow rates independent of variables which may affect other conventional production logging equipment including gas composition, inclination of the wellbore, temperature, size of tool, irregular borehole diameters and large variations in gas flow rates from different pay zones in the well.

The HRFM is capable of being stacked with other geophysical tools for both open and cased hole operations in vertical and horizontal wells.
Comparative Study of Microcomputer-Based Gas Flow Computers
Authors: Seghier M. , Podio A. L. , Dunn W. W.
Published: December 2007

A laboratory investigation was undertaken to evaluate and compare the performance of various microprocessor-based gas flow meters. A total of 45 tests were performed with both steady- and unsteady-state flow regimes to simulate field conditions.

In general, the differences in cumulative volume obtained with the seven types of metering systems studied were in the range of 2 to 7%, with the mode being between 3 and 4%. In particular, the study revealed that under unsteady-state conditions the turbine meters agreed reasonably well, i.e., less than 3% percent deviation in cumulative volume, with the orifice plate devices.

Data sampling rates were examined and found to have a pronounced effect on unsteady-state flow measurements, also, bearing in mind the generally high cost of pressure sensing elements, instantaneous values of flowing and differential pressure across the orifice were affected with randomly generated errors in order to investigate the effect on cumulative flow, and thus quantify the degree of transducer accuracy necessary to measure flow under a given set of conditions.
The Material Balance Equation for a Gas Condensate Reservoir With Significant Water Vaporization
Authors: Humphreys N. V.
Published: December 2007

In hot, high pressure gas condensate reservoirs significant vaporization of connate water can occur during depletion. As the reservoir pressure decreases, the equilibrium water vapor content of the reservoir gas increases, causing connate water within the gas-bearing portion of the reservoir to vaporize. This both increases the vapor phase pore volume of the reservoir, and decreases the hydrocarbon content of the reservoir gas. Also, condensation of liquid hydrocarbons below the dewpoint will decrease the vapor phase pore volume of the reservoir, invalidating assumptions made in a simple material balance calculation.

A modified form of the material balance equation has been developed to account for these effects. Failure to account for them- can result in erroneous predictions of gas-initially-in-place, and hence reserves. It may also lead to incorrect identification of reservoir drive mechanisms.

Field examples are presented for a gas condensate reservoir below the dewpoint, and for a gas reservoir where water vaporization effects are significant.

As targets for gas reservoirs become progressively deeper, and hotter, the significance of the effects noted in this paper increases.
Performance Analysis of In-Situ Combustion Pilot Project
Authors: Mehra R. K.
Published: December 2007

During the 1980's, BP Canada Resources Limited conducted field trials of the Pressure Up Blow Down (FUBD) wet combustion process in the oil sands deposits of Cold Lake, Alberta. The reservoir was first preheated by cyclic steam stimulation. The follow up FUBD process then took advantage of the narrow heated channels left behind to promote flooding towards the producing wells in an otherwise immobile reservoir.

This paper reviews the performance of the process. It embarks on the theoretical analysis of the process with the aim of identifying the monitoring parameters. The field performance is then analyzed and discussed. The evaluation shows that the process is capable of mobilizing significant quantities of oil but requires a much greater degree of control, without which it exhibits sharp declines in oil recoveries.
Dynamic Gas Pulse Loading Stimulations of Thermal Producers at South Belridge Field, Kern County, California
Authors: Fram J. H.
Published: December 2007

This paper details the theory, procedures and results of using Dynamic Gas Pulse Loading (DGPL)1 to stimulate over one hundred open hole, gravel packed, slotted liner completed thermal producers in the South Belridge Field located in Kern County, California. This paper will also highlight the potential uses of this technique for stimulating impaired wells completed in consolidated sandstone and carbonate formations.
Pressure Transient Field Data Showing Fractal Reservoir Structure
Authors: Beier Richard A.
Published: December 2007

Conventional pressure transient models strictly apply to areally homogeneous reservoirs. Yet, core and log data indicate this assumption is often not justified. This paper describes a model for heterogeneous reservoirs and supporting field data from the Grayburg/ San Andres formations in southeastern New Mexico. Conventional models fail to match these field data. Instead, a model for a heterogeneous reservoir with a fractal structure provides a quantitative analysis. The fractal reservoir model reduces to the conventional solution in the case of a homogeneous reservoir.
A Compositional Two-Phase Flow Model for Analyzing and Designing Complex Pipeline Network Systems
Authors: Mucharam Leksono , Adewumi Michael A.
Published: December 2007

A two-phase flow model has been developed for analyzing and designing gas/condensate distribution pipeline network system. The model is developed based on looped-system approach with some modifications. In this model, a phase behavior model is implemented for predicting the fluid properties required for the governing equations for the network system. By utilizing the Linear Theory Method, the Beggs-Brill's two-phase flow model is implemented in this model to predict the hydrodynamic variables in each leg of the network using the iterative technique which is developed in this study. A generalization of the two-phase network model is provided thereby making it possible for the two-phase flow model used to be replaced with any other mat may be more applicable for the particular situation. Using the iterative procedure developed, pressure at all nodes, gas flow rate and liquid holdup at each leg can be predicted. The test results demonstrate that the model can serve as a predictive and design tool for solving a two-phase flow problem in a pipeline network.
Oxygen Fireflooding: Determination of Maximum Water/Oxygen Ratio for Normal Wet Combustion
Authors: Venkatesan V. N. , Sampath K. , Otto J. B.
Published: December 2007

The results of a series of combustion tube tests conducted with a medium gravity crude oil from the Esperson Dome Field, Texas, are described in this paper. The effects of water/oxygen ratios (WO2R), ranging from 0 to 10 bbl/Mcf, on residual oil saturation in the burned zone, fuel and oxygen requirements, and rates of combustion/steam fronts advance were determined.

The results show that up to 7% residual oil saturation (based on pore volume) remains in the burned zone at the highest WO2R studied. Thus, one of the main benefits of wet combustion, viz., reduced fuel/O2 consumption, must be balanced against the reduction in displaced oil.

Normal wet combustion occurs at WO2R's up to 2.5 bbl/Mcf, and the steam zone ahead of the combustion front continues to grow with increasing WO2R. Oil production is accelerated and the oxygen/produced oil ratio decreases. A transition zone of constant fuel and oxygen requirements is observed as the combustion process changes from normal wet to superwet. This is the first time such data are reported for fireflooding of a medium gravity oil with oxygen. At high WO2R's, superwet combustion occurs, characterized by combustion at steam temperature.

An analytical heat transfer model successfully matches the experimental results. It predicts the minimum and maximum WO2R's for normal wet combustion. Below the minimum WO2R, the model suggests no significant growth of the steam zone. The model should be useful for estimating WO2R's in field projects.
Effect of Gelled Fracturing Fluids on the Conductivity of Propped Fractures
Authors: Parker Mark A.
Published: December 2007

Successful stimulation of an oil or gas well by a hydraulic fracturing treatment is largely dependent on obtaining a propped fracture with adequate fracture conductivity. The fracture conductivity is influenced by the reservoir environment following a hydraulic fracturing treatment. Many years of field experience have shown that it is usually necessary to use a gelled fluid to create fracture width and suspend the proppants. However, until only recently, laboratory testing methods did not realistically measure the damaging effects of these fluid systems on the conductivity of propped fractures.

As reported in recent publications, a few laboratories have constructed large scale models to simulate the pumping operation as well as the postfrac reservoir environment of a propped fracture. During pumping, treatment conditions are simulated by using a high shear flow loop to model wellbore tubular conditions, and a low shear, heated flow loop to simulate flow down the fracture. The fluid then enters a heated test cell where dynamic fluid loss in the fracture is modeled with core wafers set apart to allow fluid to flow between them and create gel filter cakes. A proppant-laden slurry is then Injected Into the gap between the core wafers and closure stress is applied.

This completes the simulation of the fracturing treatment and the propped fracture. While holding the cell at the temperature of the reservoir being modeled, the fracture conductivity is monitored for long time periods at stress progressively increasing levels of stress.

This paper describes the equipment and procedures used to accurately simulate stimulation treatment and downhole reservoir conditions. Resultant conductivity data of both sand and manufactured proppants are presented incorporating many of the commonly used fracturing fluid systems at different reservoir conditions of temperature and stress. Data comparisons are also presented whereby fracture conductivity data was obtained with both aqueous and hydrocarbon fluids as the flowing media.
Use of a Computerized Model in the Optimization of Continuous Gas-Lift Operations
Authors: Ferrer A. A. , Maggiolo R.
Published: December 2007

Corpoven, S.A. a subsidiary of Petroleos de Venezuela, S.A. has operational responsibilities in the States of Anzoategui, Monagas, Guarico, Barinas, and Apure (Figure 1). Each of these areas present specifics characteristics that dictate the use of certain producing techniques over others.

In the areas comprising the states of Anzoategui, Monagas, and Guarico, an extended degree of crude quality exists that ranges from the southern Orinoco field extra-heavy oil to gas condensate accumulations to the north. The depths of these reservoirs range from 600 ft. (183 m) to 15000 ft (4570 M). Mechanical artificial lift accounts for some 98000 BPD (15600 M3/D) from 870 active wells. Production associated with gas lift installations amounts to some 92000 BPD (14600 M3/D) from 747 active wells. Natural flow from 790 wells remains the main production mechanism, accounting for some 220000 BPD (35000 M3/D). At least 50% of this high producing rate is associated with the production from the newly discovered oil provinces in the northern sector of the state of Monagas. A large number of these high capacity wells are completed in gas, light crude or condensate reservoirs, that produce high formation gas oil ratios.

In Barinas and Apure crudes have gravities that vary between 20 and 35 deg. API. The reservoirs are characterized by relatively high productivity Indices, associated aquifers, and insignificant producing gas-oil ratios. Artificial lift methods include mechanical beam pumping units as well as electro-submersible fluid pumps. The first accounts for some 22000 B/D (3500 M3/D) from 177 wells, while the second produces some 40000 B/D (6360 M3/D) from 35 wells. Natural flow accounts for 35000 B/D (5560 M3/D) from 14 active wells that are located exclusively in the newly developed Guafita and La Victoria fields. In summary, Corpoven S.A. employs artificial lift to produce a total of 253000 B/D (40200 M3/D) of oil representing 50% of the company.s potential. A total of 1831 wells, 70% of all active completions, are employed for this production.

Corpoven operates 54 independent gas lift systems associated with 50 compressor stations and 92000 B/D (14600 M3/D/ from 747 wells. Some 574 reservoirs provide production potential for this overall system. The vast majority of these reservoirs are relatively small with NOS value ranging 5 to 200 ft. (1.5 to 6.1 M). Most are lenticular in depositional profile, with some interspersed shaliness, as well as apparent high clay content.