bluuebunny/crossref_metadata_2025 huggingface dataset:
Simulation of the North Brae Gas Condensate Reservoir Development
Authors: O'Byrne D. K. , Sadighi S. , Lane G. L.
Published: December 2007

The North Brae Field is the first offshore gas condensate reservoir in the North Sea to be developed with gas injection for pressure maintenance. The field has been on production since April 1988 and produces wet gas at a plateau rate of 440 MMSCF/D with liquid rates averaging 80 MSTB/D during the first half of 1990. Processed dry gas is currently injected to the reservoir, along with some makeup gas from the South Brae platform at rates of about 400 MMSCF/D. It is intended to continue with gas cycling until 1993 at which time the produced gas will be exported from the platform.

This paper reviews the development of the field over the first two years of producing life. Emphasis is placed on reservoir description and simulation of performance. In particular, results of a model match to compositional field data are reported for this North Sea reservoir.
Simplified Equations for Planning Directional and Horizontal Wells
Authors: Wiggins M. L. , Juvkam-Wold H. C.
Published: December 2007

Directional drilling techniques have been used for many years to reach subsurface objectives that have had inaccessible surface locations. Economic considerations and increased environmental concerns have increased the number of directional wells drilled in recent years. Directional drilling techniques have also been applied to horizontal drilling with interest in this area increasing greatly over the last several years.

In the past, there have been two major methods utilized in planning the directional well. These methods are the use of buildup or composite buildup charts and the use of several directional well planning equations, each method depending on the particular wellbore geometry desired. The use of buildup charts is a tedious process that often yields inaccurate results since it requires using preplotted graphs that require interpretation and interpolation. The equation approach is often confusing to use due to the similarity of the various equations with the selection of the proper equation dependent on the desired wellbore geometry.

This paper presents the derivation of a single equation for planning the trajectory of any directional well and a similar equation for any horizontal well. Several examples are used to demonstrate the application of the equations to various wellbore geometries.
Air Drilling and Multiple Hydraulic Fracturing of a 72° Slant Well in Devonian Shale
Authors: Yost A. B. , Carden R. , Muncey J. G. , Stover W. E. , Scheper R. J.
Published: December 2007

This paper discusses site selection, air directional drilling, stimulations, and economic evaluation for a 72° slant well drilled in the Devonian shale, Roane County, West Virginia. The well was drilled to evaluate the concept of using directional drilling and multiple hydraulic fracturing to improve the gas production from a 450-foot naturally fractured Devonian shale section. The well trajectory remained in target for more than 1,500 feet at a preferred azimuthal direction perpendicular to the regional fracture trend and also the known production fairway.

The well was conventionally drilled to the kickoff point of 2,150 feet. Afterwards, positive displacement downhole motors were used to build hole angle up to a 72° hole angle at the top of the target zone. Once the target zone was reached at 67°, conventional rotary assemblies were used to rotate the well across a 1,500-foot target section in which inclination varied from 67° to 72° of hole angle. After reaching total depth of 4,833 feet, the well was logged using wireline and drill pipe conveyed methods. Then 5 1/2-inch casing was run and cemented with 60 rigid centralizers to improve zonal isolation.

Four stimulations were designed and completed. All stimulations will be discussed in the paper. Economic analysis was conducted to show expected improvements from the application of this technology to fractured Devonian shale. Post-stimulation well testing has been identified for each zone to show initial results.
Semilog Type Curve for Interpretation of Well Test Data
Authors: Aminian K. , Ameri S. , Gaines T. E. , Morris M. E.
Published: December 2007

One of the most common, economical and reliable sources of information to determine the commercial productivity, the formation characteristics, and well conditions is the pressure transient test. However, the pressure transient test must be properly designed, run, and interpreted to provide the desired information.

The pressure transient data are usually interpreted by plotting the pressure versus time on semi-log paper. The semi-log interpretation method is often impractical due to difficulties associated with identification of the correct straight line. Type curves provide a more general method of interpretation. In this method, a plot of pressure versus time on a log-log paper is utilized to obtain a graphical match (solution) with the type curve. The log-log plots, however, then to minimize the differences in the shape of the various type curves. Therefore, a unique solution is often difficult to obtain, especially when the well test is short.

This paper introduces a methodology for interpreting well test data by utilizing more sensitive semi-log type curves. The semi-log type curves are useful for verifying the uniqueness of the solution. The methodology has been explained and discussed through several examples utilizing published well test data.
Evaluation of a Cleanout Procedure for Increasing Production From Old, Natural, Openhole Devonian Shale Wells
Authors: Hopkins C. W. , Gatens J. M. , Wallace J. L. , Ahmad M. M. , Reeves J. S.
Published: December 2007

This paper summarizes the results of a cleanout study performed on six Devonian Shale wells in southwestern West Virginia. This study was part of a joint Columbia Gas System Service Corporation (CGSSC), Columbia Natural Resources (CNR), and Gas Research Institute (GRI) project which involved 'cleaning out' shale rock debris from several old, natural, openhole Devonian Shale wells for the purpose of evaluating Devonian Shale production mechanisms. Based on well test analysis and four years of production data, it appears the cleanout procedure is economically attractive for increasing production from these types of wells.

Six wells in Mingo, Wayne, and Logan Counties, WV were selected as candidates for study. Using a cable tool rig, Columbia found the Devonian Shale openhole sections in these wells filled up and bridged off with shale rock debris. The debris was removed with a bailer, but some tool sticking problems were encountered. Post-cleanout rates increased as much as six-fold over precleanout rates as a result of these operations (73 to 411 Mscf/D for one well). Pre- and post-cleanout well test analyses performed on three wells indicated the cleanout operations resulted in increases in completion efficiency (more negative skin factors), permeability-thickness products, or both for each well. Analysis of four years of post-cleanout production data has shown the initial post-cleanout flow rates have been sustained, and it appears the cleanout operations have increased the ultimate recoveries for these wells.

Based on these initial results, CNR performed a pilot cleanout project in 1989 on four wells using a rotary rig for the cleanout operations. Many problems encountered using the cable tool rigs were avoided with the new procedure. Initial results have been encouraging.

Our analysis indicates a cleanout operation, on average, could increase estimated recovery by 210 MMscf over a 20-yr period. Assuming typical operating economic data, this increase in recovery could translate to a net present value of $197,000 per well. If 10% of the over 15,000 Devonian Shale wells in the basin were candidates for cleanout, this workover operation could translate to an increase in reserves of 315 Bscf with an associated net present value of $296 million.
Determination of the Drillability of High-Angle, Large-Displacement Wells by Analyzing the Effects of Dog-Leg Severity
Authors: Navarro A. R. , Yalcin O.
Published: December 2007

Directional wells are playing a larger role in today's drilling industry. With the development of steerable drilling systems, high angle, large displacement wells have become commonplace. The planning of these more complex well paths has created a need for an empirical analysis using previously drilled directional well data to determine the mechanical feasibility of drilling these wells when considering torque and drag, "drillability".

Data from wells drilled on South Pass Block 60 G-Platform in the Gulf of Mexico has been analyzed to develop an empirical method which will accurately predict torque and drag when planning future high angle, large displacement wells. Torque and drag prediction methods previously published (1,2), were based on the determination of the actual friction coefficient from field data. This has been accomplished by either utilizing a computer model and varying the friction coefficient until a match between calculated and measured surface torque values has been obtained or by utilizing MWD-downhole and surface weight-on-bit and torque measurements and calculating the friction coefficient on a foot-by-foot basis. These friction coefficients generally result in much lower torque and drag predictions for planned wells than are actually measured on drilled wells. These lower values may be attributed to the neglect of the effect of dog-leg severities which are introduced in the normal course of drilling or during correction runs. Previous work (3,4) used a survey simulator based on a random number generator, where dog-leg severities were controlled by an arbitrary scale factor which is called a "dog-leg severity factor".

This paper describes a more accurate method of predicting torque and drag by incorporating the effects of dog-leg severities from a survey database into an existing torque and drag simulator, for the design of the ideal well plan.
A Case History of Trempealeau Completions in South Central Ohio
Authors: Cramer J. W.
Published: December 2007

Wells drilled into the Trempealeau formation in south central Ohio require adherence to special plans and attention to detail at the price of economic success. This formation is marked by nonconformance, paraffin production, delicate oil-water contact, and a susceptibility to drilling-induced damage.

This paper provides guidelines for completion practices that have been based on 30 years of drilling in the Trempealeau formation and presents typical job designs.
New Applications of Flow Controllers for Some Field Production Problems
Authors: Weiant W. S.
Published: December 2007

This paper describes the use of flow controllers ahead of orifice meters on well locations and master stations. The controller has taken a typical production chart that was very difficult to read and made it much more accurate to integrate.

Further, the application of flow controllers at the separator as a "throttling choke" has shown numerous benefits. The elimination of choke freeze-off and improved fluid flow on combination gas/oil wells has been very successful.
Analysis of Natural Gas Production From the Mississippian Age "Second Berea" Sandstone in Southeastern Ohio
Authors: Tomastik T. E. , Cavender M. J.
Published: December 2007

The "Second Berea" Sandstone has been a prime oil and gas target in southeastern Ohio since the late 1890's. Rapid development of this horizon took place in southeastern Ohio during the 1920's and 1930"s. The introduction of hydraulic fracturing renewed interest in the "Second Berea' during the 1950's to 1960's. Dramatic price increases in the late 1970's to mid-1980's again stimulated exploration and development of the "Second Berea". Today, development of this reservoir now includes several thousand wells and encompasses an area covering 5 counties and 36 civil townships.

The "Second Berea" Sandstone is Mississippian in age and was deposited as a regressive barrier island system, which extended from Gallia County in the south to Muskingum County in the north. This unit is a very fine-to medium-grained, sub-angular to rounded, slightly shaley sandstone. Porosity varies between 6 to 14 percent, while permeability ranges from 0.012 to 0.097 millidarcies. Unit thickness varies from 0 to over 30 feet (9.84 m). Depths to the "Second Berea" range between 1000 to 2000 feet (328.08 to 656.17 m).

Natural gas production data was obtained from 111 "Second Berea" wells currently owned and operated by Columbia Natural Resources. These wells were originally drilled and completed by the Ohio Fuel Gas Company between the early 1920's to the early 1960's. Total cumulative natural gas production ranges from 40 MMscf (13.97 m3/s) to over 500 MMscf (174.60 m3/s), and averages about 134 MMscf (46.79 m3/s) per well.
An Application of an Expert System for Bailing Operation Management: Field Case Study
Authors: Yu J. P. , Suhy T. E. , Cheong P. , Yang J. R. , Zhao D.
Published: December 2007

The success of a bailing operation depends solely on management in order to keep the operation economical. A novel approach to solve this management challenge is to use an expert system. To automate the bailing evaluation the required knowledge base was divided into one main frame and two subframes. The non-quantitive data are translated to computer form using the rule-based approach. The main frame determines the number of wells for bailing and each subframe handles operational problems.

This paper presents field applications. About twenty wells were selected and pertinent data were stored in database form. Primary priority of the bailing wells were set according to the predicted bailing gain and date with a special decline curve analysis program. Then, the expert system evaluated individual well according to the operational constraints and problems. Since the expert system interacted with the database system, one database file listed all the bailing wells and the other list all the operational problems for future reference. The bailing operation is found to be more efficient and economical.
Hydraulic Fracturing Techniques Used for Stimulation of Coalbed Methane Wells
Authors: McDaniel B. W.
Published: December 2007

Methane gas from wells completed exclusively in coal seams has become a major energy resource in the USA, and it is being evaluated in many other countries. In all but a very few cases, stimulation by hydraulic fracturing is required for adequate production rates. The application of fracturing to improve degasification of coal beds prior to mining began in 1974, but in recent years its application has expanded such that many completions are independent of any expected future mining operations. Wells are often completed in multiple coal seams with possibly hundreds of feet between the completion zones.

The hydraulic fracturing fluids, equipment, and designs used for coalbed methane wells have seen major evolutionary changes from the early treatments when completing in seams to be mined. When fracturing became common in coal seams where mining was not being considered, roof integrity was no longer a concern and the treatment designs began to undergo more accelerated changes.

This paper will trace the historical application of hydraulic fracturing in the two major commercial coalbed methane producing areas: The Black Warrior Basin of Northern Alabama and the San Juan Basin of Northwest New Mexico/Southwest Colorado. Recent applications in the Raton and Piceance Basins of Colorado and the Central Appalachian Basin will also be addressed.
Horizontal Drilling Success Offshore Abu Dhabi
Authors: Muriby A. C. , Youssef M. , Mostafa A.
Published: December 2007

The oil industry's remarkable achievements in horizontal drilling encouraged Upper Zakum Development Company, ZADCO, under the auspices of Abu Dhabi National Oil Company, ADNOC, and in cooperation with Abu Dhabi Marine Operating Company, ADMA-OPCO, to consider and successfully implement the medium-radius technique in two low-productivity wells of west Upper Zakum Field.

This paper will discuss the strategies used for planning the two wells. Operational aspects and experience gained will also be detailed.
Transition Zone Exploration – A New Seismic Approach
Authors: Ebed Atef
Published: December 2007

Transition zones (coastal areas connecting marine and onshore) are known to constitute a hazard in seismic exploration. The establishment of accurate ties between various modes of seismic surveys (Land, Shallow Marine and Marine) should therefore be carefully considered/achieved during both data acquisition and processing phases.

Variations in water depth, sea bottom topography, the crossing of small islands and/or reefal bodies normally impose constraints on the selection of optimum data acquisition parameters. Flexibility/versatility of methods and equipment are of utmost importance in securing adequate results. Multi-various combination of energy sources (airgun, dynamite, vibroseis etc.) and receivers (hydrophones, geophones, marshphones etc.) could be used within the one and the same survey to secure maximum continuity of seismic reflections.

Seismic data acquired in the transition areas require the application of special processing parameters due to amplitude and phase distortion resulting from the use of various sources and receivers. Sophisticated and advanced processing techniques are therefore essential to generate continuous and well matched seismic sections across the transition areas.

Optimum processing results can only be achieved in case good quality data is acquired. This should enable better identification of subsurface structures and stratigraphie plays that may be present, and consequently enhance possibilities for the detection of hydrocarbons.

Seismic data acquired and processed through the application of new techniques undoubtedly reveal better definition and resolution of subsurface traps, when compared to data recorded using old methods.

All examples and illustrations presented in this paper were extracted from seismic data, acquired in ADNOC Concession Areas, in Abu Dhabi, United Arab Emirates.
Correlation of PVT Properties for U.A.E. Crudes
Authors: Dokla Mahmoud E. , Osman Mohammed E.
Published: December 2007

PVT properties are important reservoir parameters. Correlations are used whenever experimentally derived PVT data are not available. No universal PVT correlation is available and data from local regions are expected to give better approximation to estimated PVT values.

Available PVT data from UAE reservoirs was used to obtain correlation equations for bubble point pressure and oil FVF as function of oil specific gravity, gas gravity, solution GOR, and reservoir temperature. Error bounds of the obtained correlations are calculated and compared to other correlations available in the literature. The correlations of this study result in lower errors and should work better for UAE crudes.
Gas Condensate Reservoir Evaluation Using an Equation of State PVT Package
Authors: Savary D.
Published: December 2007

Gas-condensate reservoirs are among the most difficult problems in practical Reservoir Engineering. In case the reservoir is saturated (which is the most frequent) it is impossible to obtain a representative reservoir fluid sample, because any production will create a draw down at well bore level, and some condensed liquid will be left in the formation.

On the other hand, behaviour of a gas-condensate reservoir is mainly controlled by fluid properties, and accurate knowledge of these PVT characteristics is required.

The former methods for PVT calculations (corresponding states law, K-value correlations) were rather tedious and of limited accuracy. The introduction of Equation of State and progress in computers has resulted in modern PVT packages which can accurately simulate fluid behaviour with a reasonable work involved.

The objective of this paper is to illustrate how such a modern PVT package can help in solving practical reservoir engineering problems on a gas-condensate field offshore Abu Dhabi.

Example shown includes:

Reconstitution of the original reservoir fluid using a sample obtained at flowing pressure below dew-point. Calculation of initial gas composition change with depth in the reservoir, down to the gas-oil contact. Condensate-gas ratios measured in various conditions during life of the reservoir can vary a lot: a PVT package helps in explaining these differences and selecting the best data. Performance of lean gas injection into a depleted reservoir containing immobile condensed liquid, and how it improves condensate recovery.
Application of Short-Radius Lateral Drilling Technology in the Divided Neutral Zone Between Saudi Arabia and Kuwait
Authors: Kumamoto K.
Published: December 2007

In 1989 short-radius lateral drilling technology was applied in the Khafji Field which is situated in the Divided Neutral Zone between Saudi Arabia and Kuwait.

First two lateral holes, with a combined horizontal displacement of 1389 ft, were drilled in a limestone which has two porous oil-bearing layers separated by a tight limestone, starting from one existing vertical production well. The aim in so doing was to enhance the rate of oil production.

A third lateral hole, with a horizontal displacement of 309 ft, was drilled in an unconsolidated oil-bearing sand formation which is characterised by bands of sloughing shale, starting from another existing vertical production well which was suffering water coning. From the standpoint of wellbore stability this sand formation had been considered to be too unstable to carry out horizontal drilling. The aim in view here was also to enhance the rate of oil production. However, the main intention was to prevent the problem of water coning.

Lateral drilling in the limestone was completed without any difficulty.

Inclination was able to be controlled by changing the bottom hole assembly. Drilling was carried out-until the allowable maximum rotary torque was reached.

However, during lateral drilling in the. sand formation many problems occurred – i.e. low rate of penetration, short bit life, severe dragging during trips, differentially stuck, etc. These problems were due to the high mud weight which was considered to be necessary as a result of an analysis, taken together, of a microfrac test and a rock mechanics study which had been carried out. The aim here was to stop the hole collapsing. In this case inclination was not controllable. The well path kept on rising continuously.

This paper will discuss how the well was drilled, the problems encountered in the process and how these were overcome.
Safah Field: A Case History of Field Development
Authors: Vadgama U. , Ellison R. E. , Gustav S. H.
Published: December 2007

Safah field located 415 kilometers west of Muscat, The Sultanate of Oman, produces 42 degree API oil from the Upper Shuaiba Formation of Lower Cretaceous age. The paper describes how the operator has cost effectively developed the so called "marginal" field where the average well produces about 250 BOPD. The paper presents the geology and reservoir parameters along with the reservoir simulation results used to determine the well spacing. It reviews the on going gas injection project as describes the future development plans.
Hydrocarbon Generation and Migration in the Paleozoic Sequence of Saudi Arabia
Authors: Abu-Ali M. A. , Franz U. A. , Shen J. , Monnier F. , Mahmoud M. D. , Chambers T. M.
Published: December 2007

This paper is a progress report on geochemical studies of the Pre-Khuff Paleozoic Sequence in Saudi Arabia, summarizing current laboratory results from both Saudi Aramco and U.S. Companies and their preliminary interpretations.

Oil-oil and oil-source rock correlations indicate that Pre-Khuff Paleozoic oils and condensates are closely related to each other because they have a common source, the "hot shale" at the base of the Qusaiba shale Member of the Qalibah Formation. Oils and condensates in the Hawtah trend have been generated from highly mature Qusaiba shales. Since Paleozoic source rock maturities are no more than marginal in the producing trend, hydrocarbons must have migrated generally westward from the presently overmature Udaynan depocenter of the Rub-Al-Khali Embayment. Indeed, maturity measurements and computer-assisted maturity modeling clearly indicate that oil generation and updip migration commenced as long as about 160 million years ago (MA). Residual oil was cracked into condensate and gas when the depocenter passed into a higher temperature regime beyond the oil window, approximately 90 MA. Thus, the light hydrocarbons produced in the Hawtah trend can be considered the result of a "natural refinery" process at depths in excess of approximately 13,000 ft. (3962m) and temperatures around 350°F (177°C). Late stage non-hydrocarbon gases should be co-generated in the very overmature depocenter (over 2% Ro) at present. The likely source for such gases is pyrobitumen, the residue of cracked oil. Pyrobitumen is found in many deep wells where it has a pore-plugging effect. Advantageously all of the hydrocarbons are sulfur-poor because the initial kerogen was sulfur-poor. This difference between Saudi Arabian Paleozoic and Mesozoic oils is extremely important economically!
Use of Oil-Base Gel System for Multiple Proppant Fracturing of Horizontal Wells
Authors: McCabe M. A. , Champetier J-L. , Edwards M. G. R.
Published: December 2007

This paper describes the planning, laboratory evaluation, and fluid system development for a fracturing treatment on a horizontal completion in the Sahmah Field, Sultanate of Oman. The Sahmah field consists of two reservoirs, the Lower and Upper Haushi, part of the Permian age. The Upper Haushi comprises a sandstone formation overlying a dolomite bed. The sandstone is deep, hot, and has low permeability with pockets of moderate permeabilities throughout. In the past, improvement in productivity has been successful with hydraulic fracturing treatments. A horizontal completion in the sandstone with a combination of multiple fracturing treatments placed in the horizontal wellbore was considered as a method for optimizing production in the Sahmah field.

The isolation of the field created logistic and well servicing problems, so four separate hydraulic fracturing treatments, to be performed prior to flowback, were planned. The laboratory testing carried out for fluid selection and fracture modeling for the horizontal completion form the basis of this paper.
Casing Design Considerations for Horizontal Wells
Authors: El-Sayed A-A. H. , Khalaf F. , Ghzaly S. M.
Published: December 2007

Horizontal Drilling is now a well established technique with growing popularity for exploiting a number of reservoirs which would otherwise be noncommercial. However a horizontal well requires a substantial engineering work compared to conventional directional drilling. Significant advances in drilling technology have made it possible to drill horizontally in almost any situation by using very specialized tools. But some inherent weaknesses to this technique still exist, like casing design. Most of the reported horizontal wells are completed with open hole or slotted liner. This type of completion is simple and inexpensive, but may not furnish enough support to the walls of the well to allow for long well life.

This paper discusses casing design considerations for horizontal wells. It addresses the type and nature of loads applied on casing strings set in horizontal wells; examples of these loads are torque and drag, formation subsidence, effect of perforations, and bending loads. A design method for casing string under loads that prevail in horizontal wells is also included. The proposed design method shows that the horizontal section needs high collapse resistance pipe or thick-wall pipe to avoid casing failure due to non-conventional loads that prevails in horizontal wells.
Prediction of Stratigraphic and Areal Occurrences of Jilh High Pressure in Bahrain Field
Authors: Mohamed A. N. M. , Khalaf A. S.
Published: December 2007

Bahrain field is an asymmetrical anticline trending in the North South direction. The sedimentary column extends from Cambrian Saq Sandstone to the Miocene reefal deposits, exposed on the surface.

Jilh Formation is of Middle Triassic age. It is named after Jilh Al-Ishan escarpment, Lat 24° 04′ North, Long. 45° 46′ East, in Saudi Arabia across which the type section was measured. The top of Jilh is marked by a regional unconformity that has caused the complete erosion of the Minjoor Sandstone of upper Triassic and the partial erosion of Jilh Formation in the Bahrain Field. The preserved thickness of the Jilh Formation in Bahrain Field ranges from 800 feet (244 meters) on the crest to 1380 feet (420 meters) on the flanks.

Extremely high pressures were encountered in the Jilh Formation at depths ranging from 7000 to 8000 feet (2135-2440 meters). These abnormally pressured zones are usually associated with gaseous brines and have pressure gradients ranging from .65 to .88 PSI/FT (1.5 to 2.03 gram/cc).

The lateral pressure compartmentation necessary for creating the abnormally pressured zones is apparently formed by the central graben faults and the perpendicular minor antithetic faults. The pressurized brines are believed to have been sourced from the clayey sections of the Jilh Formation.

The Jilh high pressure zones are difficult to drill through unless the depth and the lateral distribution of these abnormal pressures are known. This paper will attempt to describe an approach for predicting the occurrences of abnormal high pressure zones in the Jilh formation ahead of drilling to facilitate the casing design and minimize risks normally associated with such phenomenon.
A Simplified Method for Computing Phase Behavior of Carbon Dioxide/Hydrocarbon Mixtures in Compositional Simulation
Authors: Mohammed S. A. , Wattenbarger R. A.
Published: December 2007

A K-value method, which is designed for fast computation, is presented. The method relates the K-value of each component with its boiling temperature, critical temperature and pressure, the mixture's pressure and convergence pressure, and overall compositional changes. Experimental data, from routine PVT tests of the mixture, are used to calibrate the K-value correlation.

A PVT simulator was developed to model the routine PVT laboratory tests. This simulator generates the K-value correlation for the mixture and employs a least squares-linear programming optimization routine to fine tune the correlation such that the simulated PVT behavior matches the actual one.

Nine reservoir fluid samples, four of them included carbon dioxide miscibility, were used to demonstrate and test the applicability of the new K-value method. The method has proven successful for predicting the phase behavior of hydrocarbon systems as well as the carbon dioxide-hydrocarbon mixtures.

The new method was compared with Peng-Robinson, Soave-Redlich-Kwong, and Schmidt-Wenzel equations of state which were embodied as options in the PVT model. The comparisons of the fluid samples have shown that the new method is reliable and is faster than the equations of state by a factor of seven to twenty. The method requires no iterations, less computer memory, less input data, and fewer tuning parameters than equation of state methods.
Comparison of Formation Microscanner Images to Cores in Sandstone Reservoirs, Saudi Arabia
Authors: McNaboe G. J.
Published: December 2007

The Formation MicroScanner (FMS) tool was first run in Saudi Arabia in 1986. Since then, both the tool and software used for viewing and manipulating the FMS images have been improved. Recent developments in interactive software by Schlumberger have greatly increased the usefulness and ease of interpreting the FMS images. The FMS log is better than the dipmeter because it allows calculation of dips in the presence of fractures and in zones of poor lateral continuity.

The FMS uses arrays of microresistivity sensors to make high resolution images of the borehole. The images are displayed on a variable intensity color scale with sufficient resolution to enable comparison to core photographs. Detailed FMS analysis requires the use of an interactive computer-graphics workstation for image enhancement and dip calculations.

The FMS images were found to be effective in the interpretation of sedimentary structures, paleocurrent direction, thin bed analysis, depositional environment, and fracture identification. Because of the photo-like quality of the images, features such as concretions, rip-up clasts, bioturbation, flaser bedding, and grain size changes can often be identified. Also faint crossbedding in core may be more obvious on the images as the microresistivity contrast is often greater than the visual contrast.

Once the FMS images have been calibrated with core data, the FMS log can be an effective way to reduce the need for core in offset wells. At times a FMS image is better than conventional core since true dip azimuth and magnitude can be calculated.
Analysis and Evaluation of Tubing-Conveyed Perforating vs. Through-Tubing Perforating
Authors: Sobh A. A. S. , El Sharkawi A. W. M.
Published: December 2007

In GUPCO'S operations, different perforation types and techniques had been used for new completions, workovers, conversions and drill stem tests in Gulf of Suez and Western desert fields.

This paper presents a case study of Tubing Conveyed under-balance Perforating (TCP) jobs versus Through Tubing Perforation (TTP) jobs and Casing gun perforation jobs conducted in GUPCO'S fields during the period from January 1980 until April 1991.

In the past the conventional over-balance perforating types, TTP (Through Tubing) and Casing perforations, were being used in all perforation jobs performed till late 1983. In October 1983 the under-balance tubing conveyed perforating technique was used for the first time in the well M-107 in E1 Morgan field. As a result, the well was produced 7500 BFPD with 6% W.C. Then the TCP applications increased sharply and become the most usable perforation type today.

The perforation job is the most important step in the well completion as it represents the last portion of the reservoir inflow. Consequently, it directly affects the well productivity.

The determination of the proper perforation type and technique will results in both cost savings and improving well productivity.

This paper documents only those perforation jobs performed utilizing rigs including new completions, recompletions, conversions and workovers. More than 1600 rig jobs were performed during the period from January 1980 until April 1991. Out of these jobs, 993 perforation jobs were conducted and will be analyzed in this paper.
New Minifrac Procedure for Simultaneous Determination of Early and Late Time Fluid Loss During Fracturing
Authors: Lee W. S.
Published: December 2007

Subject paper describes a novel new minifrac treatment procedure that allows the simultaneous determination of both early time fluid loss rate, (Cvc), and late time fluid loss rate, (Cw) when a filter cake has become the controlling factor. One of the primary uses of minifrac tests prior to stimulation of a zone is to determine the fluid loss coefficient, (Ceff), which plays a key role in treatment design. The value is the weighted average of Cvc and Cw. In applications in which early time fluid loss is low, this method gives reasonable results; if permeability is high the method is not valid. An excessive pad volume can be predicted in simulators when values computed by present methods are used.
Experimental and Modeling Evidence for Major Changes in Hydraulic Fracturing Design and Field Procedures
Authors: Cleary M. P. , Wright C. A. , Wright T. B.
Published: December 2007

The paper presents some important conclusions obtained by analysis of data from many hydraulic fracturing treatments monitored over the past five years. These conclusions involve some major changes from conventional concepts about hydraulic fracturing, many of which have been based on inadequate models of the process and a commensurate lack of adequate data or motivation to check those models. Recommendations are, therefore, also made about simple, low-cost procedures for adequate data collection, such as the use of flow-rate changes and/or multiple injection/shut-in cycles for stringent model evaluation. Our conclusions from such careful analysis include: shorter, wider fractures; relative insensitivity of fracture width to frac-fluid rheology; dangerously fast convection vs. settlement of proppant in imperfectly-contained fractures; and a potential role of natural fractures in explaining many phenomena formerly regarded as evidence for long contained fractures. Although serendipity may sometimes compensate for poor job design, we recommend that many existing approaches to fracture design and execution be re-considered and that more credible efforts at treatment optimization be achieved by more careful (on-site) analysis of properly monitored and more flexible field execution schedules.
Improving Fracture Conductivities with a Delayed Breaker System: A Case History
Authors: Small Joe , Wallace Mike , Howe Steve Van , Brown Ernie , Pferdehirt Doug , Thompson John
Published: December 2007

A case study has been conducted on over 90 gas wells in West Texas to optimize fracture conductivity and well profitability. This study provides direct comparisons evaluating the effectiveness of treatments incorporating various designs and breaker systems. The wells stimulated with new designs focusing on methods to improve fracture conductivity have shown significant increases in production rates. These same wells have also shown improved clean-up properties, as compared to surrounding wells, by eliminating swabbing time and returning higher volumes of fracturing fluid.

Recent laboratory studies have demonstrated that realistic in-situ fracture conductivity values are significantly lower than previously thought. New testing procedures have concluded that proppant permeability values are greatly reduced when exposed to long term tests. Additionally, fluid damage and polymer concentration further impair these permeability numbers. When breaker concentrations are increased to a level to effectively degrade the concentrated polymer the rheology of the fluid will be adversely affected, thus sacrificing the execution of the treatment.

New designs have evolved placing emphasis on proper fluid selection, increasing proppant volumes and concentrations, and improved breaker scheduling. Encapsulation techniques have been developed allowing a controlled delay of breaker activation until after the proppant is placed. Extremely high breaker concentrations are now obtainable without adversely effecting the rheological properties of the fracturing fluids.
The Development of a Low-Permeability Gas Reservoir, Hamitabat Field, Turkey
Authors: Memioglu E. , Agca C.
Published: December 2007

The purpose of this study is to evaluate and summarize the production history, tests, hydraulic fracturing operations and previous reservoir engineering and deliverability studies performed for Hamitabat natural gas field located in Thrace Region, Turkey (Figure 1). The structure and description of the reservoir, deliverability of the field, production increase as the result of stimulation operations, existence of an aquifer and change in reservoir pressure due to production have been either revised or determined.
Proseparator: A Novel Separator/Scrubber Design Program
Authors: Baker M. , Dick D. R.
Published: December 2007

Prediction of performance of Separators and Gas Scrubbers is difficult with the traditional design methods - especially if inlet liquid loadings are high. BP Engineering has developed a novel Separator Design Program that can quantify the performance of both conventional and proprietary separation units.

The technique predicts the particle size distribution in the inlet pipework and determines the liquid Knock-Out in the vessel body. The quantity and size of remaining particles is calculated to enable the expected performance of the internals (Vanes, Cyclones or Demister Pad) to be estimated.

Initial verification work of this method by checking against existing operating units is now complete and a programme of further research work and development is in progress by BP Research, AEA-Harwell and BP Engineering.
Recent Developments in Gas Dehydration and Hydrate Inhibition
Authors: Hubbard R. A.
Published: December 2007

Dehydration is an essential step in the processing of natural gas to meet pipeline specifications. Water removal is required to prevent condensation of an aqueous phase which can lead to hydrate formation and corrosion in the gas handling system.

The purpose of this paper is to review commercial natural gas dehydration processes and recent developments which impact the installation and operation of these facilities.

The paper will be divided into three sections 1) review and history of gas dehydration processes, 2) water-hydrocarbon equilibrium behavior and 3) new developments in gas dehydration processes.
Effects of Orifice Meter Installation Condition on Orifice Coefficient Accuracy
Authors: Morrow T. B. , Park J. T. , McKee R. J.
Published: December 2007

The effects of tube bundle straightening vane location on orifice meter Cd and axial velocity profile have been investigated for nitrogen flow at a Reynolds number of 9*105 in a long (45 D), 4 inch diameter (100 mm) meter tube downstream of a 90° elbow. A 19 tube bundle straightening vane was modified to allow changing the vane to orifice distance, (x/D), without reassembling the meter tube. Results are presented for Cd variation for β=0.75 and 0.40, and for axial velocity profile as a function of x/D from 5 to 42.5.
Application of a New Wave Theory to Offshore Design Problems
Authors: Wallace Norman R.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

This paper was prepared for the 43rd Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Houston, Tex., Sept. 29-Oct. 2, 1968. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

A theory has been developed to describe the shape and velocity field of nonlinear waves in extreme states of deformation equally as well as in the undeformed state. The wave properties can be calculated for successive instants during the deformation process. Thus, the entire time-history and distribution of forces on objects causing the wave deformation are determinable.

A description is given of the method and application to the case of solitary waves impinging on a 45 degrees slope. Extension of the method to treatment of nonlinear, periodic waves and to forces on submerged pipelines is discussed.

Introduction

Offshore structures must be designed to withstand forces exerted by the largest waves expected to occur at the site of installation. Often these design waves are assumed to be the largest that can be supported by the depth of water, but even in less extreme situations the nonlinear character of finite-amplitude wave motion is usually taken into account. Stokes' waves in the third and fifth order of approximation are commonly used for the design wave in water of intermediate depth. For very large waves in shallow water, cnoidal wave theory has been found appropriate. As a third alternative, the individual crests of a shallow water system can be considered solitary waves, and McCowan's description (reference 1) of this wave and its particle velocity has found wide acceptance.

All of these theoretical methods pertain to periodic wave trains or pertain to periodic wave trains or single waves in water of constant depth. These methods cannot accommodate changes in the shape of the wave caused by the structure on which it impacts, yet these changes can be highly significant.

A new theory will be discussed here.
Gas Well Test Analysis in Complex Heterogeneous Reservoirs
Authors: Kocberber S. , Collins R. E.
Published: December 2007

Today reservoir engineers are faced with the challenge of evaluating well tests in heterogeneous, complex reservoirs which may include fractures. For such reservoirs analytical methods are not available so numerical simulation is required. We present a finite element simulation system for gas well test analysis in such reservoirs. An automatic finite element grid generation technique provides grid refinement only in regions where it is needed. In this way wells and fractures are rigorously represented. Also wellbore storage and skin effects can be included in the model. Analytical coupling of fracture flow equations with reservoir flow equations, and nonlinear treatment of gas viscosity and compressibility, make the model ideal for gas well testing in fractured reservoirs. Also included in this 2-D model is the the capability of simulating multi-layer, 2-D reservoirs with crossflow only at the wells in a numerically efficient way. The model has been validated against analytical solutions for liquid flow in homogeneous media and has been shown to be correct to high order accuracy.
Sensitivity Analysis of Key Reservoir Parameters in Gas Reservoirs
Authors: Arastoopour H. , Chen S-T.
Published: December 2007

A history match for gas and water production from Travis Peak Formation in the Eastern Texas Basin using our numerical simulator was performed. In our simulator, unlike dual porosity models, we used one general equation for both fracture and matrix, and variable computational cells. This enabled us to reduce the size of the computational cell close to fracture size which is closer to real situations in the gas reservoirs, and in turn, we believe our prediction is more accurate and reliable. Other advantages of our approach are: a) the flow equations in the fracture are not oversimplified, and b) the fracture system is not restricted to network of fractures.

Gas and water production predicted using our modified program agreed well with 30 days of production data from SFE No. 1 in Travis Peak formation. The effect of permeability, porosity, capillary pressure, viscosity of fracturing fluid, the level of invasion of formation by fracturing fluid and presence of single and multiple fractures on production were studied. Our calculation showed that interfacial forces between gas, water and porous medium are the most sensitive parameter effecting the enhancement of the gas production. Furthermore, the increase in overall mobility of the porous medium of reservoir due to presence of the fractures does not have significant effect on production in comparison with the location and distribution of the fractures.