bluuebunny/crossref_metadata_2025 huggingface dataset:
The Western Rub' Al-Khali Infracambrian Graben System
Authors: Dyer R. A. , Husseini M.
Published: December 2007

A major Infracambrian graben system is observed along regional seismic reflection profiles in the Western Rub' Al-Khali of Saudi Arabia. This graben system was formed coincident with the development of salt basins in Oman and the Arabian Gulf, and the Najd fault system of the Arabian Shield. Evident structural elements include the northwest-southeast trending Najd faults, and the more commonly recognized north-south trends.

The sediments deposited in the grabens can be divided into three units based on seismic character. The inferred basal unit is relatively free of seismic reflections and has an indefinite basal seismic reflector. The middle unit contains parallel seismic reflections marked by high comparative amplitude and continuity. The upper unit represents an eroded wedge characterized by low internal seismic reflectivity.

The three units are correlated with the Infracambrian Huqf Group of Oman and the Jubaylah Group of the Najd system of the Arabian Shield. Specifically, the basal unit is interpreted to correspond to the coarse clastics of the Abu Mahara. Formation at the base of the Huqf Group and the Robutain Formation of the Jubaylah Group. The middle seismic unit is interpreted as carbonates and marine clastics, equivalent to the Khufai, Shuram, and Buah Formations of the Huqf Group and the Muraykhah Formation of the Jubaylah Group. The upper seismic unit is interpreted as the clastic facies equivalent of the Ara Formation salt of the Huqf Group.

The carbonates of the Huqf Group of Oman are the proven source rocks of oil fields in the Ghaba and South Oman Salt Basins, and therefore the middle seismic unit of the Western Rub' al-Khali graben system may also be regarded as a potential source rock. The faulting associated with the graben system is terminated by a major unconformity which separates the syn-rift sequence from the post-rift sandstones of the Saq Formation of Saudi Arabia.
Sabkha vs. Salt Basin Model for the Arab Formation Understanding in the Umm Shaif Field, U.A.E.
Authors: Lapointe P. A.
Published: December 2007

The Arab Formation forms the principal oil reservoir of the Upper Jurassic sequence in the Middle East. Previous studies (1) carried out on the cores of the Umm Shaif field, Abu Dhabi offshore areas, led to nine distinct sabkha cycles, assuming that a "giant" sabkha system was prevailing during the lower Arab to the top of the Hith deposition covering a very largely extended area.

Recent regional and detailed field studies provided new information and highlighted some comments on this sedi-mentological model.

A revised model is therefore suggested, based upon the contemporaneous deposition of marine gypsum in deeper inter algal mounds or bioclastic shoal areas (shallow water evaporites) and restricted more basinal areas (intrashelf basin, relatively deep water evaporites). The sabkha fades could however appear during relative sea level fall onto small areas
Non-Darcy Flow Behavior in Partially Penetrating Gas Wells
Authors: Erarslan S. , Ayan C. , Lee W. J.
Published: December 2007

In this study, the combined and separate effects of partial penetration, skin factor and non-Darcy flow were studied. Flow tests were simulated using a single phase numerical model, which also incorporates non-Darcy flow effects. IT-flow factors calculated from the model were compared with the values obtained from existing methods. A new equation to predict the IT-flow factor in presence of wellbore damage and partial penetration is presented.

The new equation successfully predicted the IT-flow factors, whereas, the common method gave underestimated values. The IT-flow factors from well tests were used to calculate the velocity coefficients using the common methods. In presence of partial penetration and wellbore damage, these values were found to be overestimations.
Further Investigation on the Analytic Solutions for Finite-Conductivity Vertical Fractures
Authors: Azari M. , Wooden W. O. , Coble L. E.
Published: December 2007

The analytical solutions1 based on the tritinear2 fracture flow model are used to further study effects of linear skin on the fracture, fracture to formation height ratio, wellbore and fracture storages, fracture to formation hydraulic diffusivity ratio, and phase segregation on the pressure profile of finite-conductivity, vertically fractured wells.

The analytic solutions for the constant-rate and the constant-pressure cases for both infinite and bounded reservoir conditions in conjunction with a unique asymptotic approach to pseudoradial flow are used to produce the corresponding type curves. The combined solutions provide all the possible flow regimes encountered in pressure transient testing of any finite-conductivity, vertically fractured formations. They present wellbore and fracture storage, early-time unsteady-state fracture linear, bilinear, skin on the fracture dominated, formation linear, pseudoradial, and pseudosteady state flow periods.
On the Interpretation and Design of Horizontal Well Tests
Authors: Temeng K. O.
Published: December 2007

The paper discusses several issues related to the interpretation of transient pressure tests on horizontal wells. Horizontal well type curves incorporating the effects of wellbore storage and skin are used to aid in the diagnosis of and estimation of parameters from test data. Issues addressed in this study include the identification of flow regimes. validity of Horner graphs. and analysis of multirate tests. An example interpretation is discussed to illustrate concepts.

It is shown that for other than the most ideal situation, the early radial flow behavior will not be evident. In tests with short flow or buildup periods, it is possible for wellbore storage and skin effects to mask both the early radial and linear flow periods. Where early radial flow is present, it is shown that as long as flow length is very long compared to shutin time, a Horner plot may be used to compute formation parameters.

In the general case. type curve matching procedures provide adequate means for estimating the desired parameters from the well test.
New Correlations for Time Lags and Pressure Response Amplitude in Pulse-Test Analysis
Authors: El-Khatib N. A. F.
Published: December 2007

The equations for pulse test analysis by the tangent construction method are formulated in a general way to account for the possibility of the time lag exceeding the pulse or shut-in periods. The equations are solved for the dimensionless cycle period and response amplitude for a wide range of the relative time lag for the first four cycles and at different pulse ratios between 0.1 and 0.9. Cases with difficulties in solving the equations are discussed and their physical and mathematical interrelations are explored. A single set of correlation curves for the dimension-less cycle period is presented for all cycles while a seperate set of curves for the dimension-less response amplitude for each of the first four cycles is needed. The significance of using correlations for the three time lags is discussed.
Status and Scope for EOR Development in Oman
Authors: Al-Adawy M. S. , Nandyal M.
Published: December 2007

In view of a significant STOIIP (3000+ million m3) of medium/heavy oil (less than 31° API), EOR development in Oman has been and remains a major strategic option in its challenge to increase recovery and to meet long term production requirements.

The initial EOR Development Programme (1980-89) of which results are highlighted in this paper was based on a series of pilots and tests to gain experience and reduce uncertainties prior to embarking on wider EOR application. The processes tested included Steam and Polymer Flooding in the Marmul field. Steam Soak in five South Oman heavy oil fields and Hot Water Injection in the Qarn Alam field. A wide range of reservoir types, oil characteristics and reservoir drive mechanisms have been covered in this test programme.

Results on Polymer Flooding and Steam Soak were rather encouraging and presently small-scale follow-up projects are being pursued in the Marmul and Amal (Eastern High) fields respectively.

Due to geological complexities and reservoir heterogeneities in the Al Khlata sands of the Marmul field pilot area, Steam Flood performance was rather poor and performance extrapolation to other reservoirs is difficult. However, scope exists for those fields with thick, well connected homogeneous sands, with

Steam Soak considered as a precursor to Steam Flood.

The Hot Water Injection Test performed in the unusual oil-wet fractured carbonate reservoir in Qarn Alam, did not provide the predicted wettability reversal for field-wide application. Processes to accelerate gas-oil gravity drainage mechanism in this reservoir are currently being evaluated.

The initial programme has provided the necessary operating/technical knowledge to enable new projects to be better defined. Thus, an overview of future EOR scope taking into consideration the current oil economic climate is developed and presented.
Gas Saturation Monitoring in North Oman Reservoir Using a Borehole Gravimeter
Authors: Adams S. J.
Published: December 2007

Following partial implementation of gas/oil gravity drainage as the primary recovery process in the Natih Field, Petroleum Development Oman undertook a gas saturation monitoring campaign to determine its effectiveness. Evaluation based on thermal decay tool measurements produced secondary gas saturations lower than anticipated from material balance considerations.

It was reasoned that the limited depth of investigation of the nuclear tools may have been insufficient to sample formation representative of the reservoir. In order to resolve this uncertainty a number of wells were surveyed using the borehole gravimeter as a deep reading formation density tool. Comparison with original porosity measurements obtained using conventional devices enabled quantitative gas saturations to be evaluated. Confidence in the method was obtained by additionally running the tool across the same formation in a gas reservoir.

Results indicate that the gravimeter can be used to quantify gas saturations to within a 15% range. The gravimeter has proven effective in situations where conventional neutron and thermal decay gas monitoring tools are limited by their depth of investigation.

The accuracy of the method is constrained by the control of distance between discrete gravity stations, the borehole and cable noise and the confidence with which the reservoir porosity is known. In low porosity systems the accuracy is degraded.

As a consequence of the higher gas saturations evaluated using the Borehole Gravimeter, implementation of full scale gas/oil gravity drainage in the Natih Field will continue.
Using Electrical Logs To Obtain the Saturation Exponent (n) in the Article Equation
Authors: Watfa M.
Published: December 2007

The saturation exponent (n) is an essential parameter that is required to solve the Archie Equation and obtain saturation values. This equation gives correlations between resistivity, porosity and saturations. When core measurements of n are unavailable, its value is assumed constant (usually 2). However, under certain conditions, this assumption of a constant value could lead to large errors in computed saturation values.

This paper presents a technique whereby electrical logs are used to solve simultaneously for n and the water saturation values Sw and Sxo in the uninvaded and invaded zone respectively. This technique combines open hole log values which are sensitive to saturation, namely the deep reading resistivity Rt, the shallow resistivity Rxo, and the electromagnetic transit time tpl, together with the through tubing cased hole measurement of the formation capture cross-section (Σ). Essentially four equations are used to solve for Sw, Sxo, n and the porosity exponent (m) at every log sampling point.

A data-base containing log data from 22 wells was constructed from the Upper Jurassic Arab Formation. This is a carbonate reservoir with anhydrite. The porosity distribution in sections of this formation is known to be heterogeneous, with the presence of vugs and fractures. The results of this study showed that the Arab Formation is water wet, and the computed values of n are consistent with the range of values obtained from core measurements. The n values were found to increase with increasing dolomitization, and were shown to be independent of both the pore type and of the porosity exponent m. The results presented demonstrates satisfactorily that this technique, under particular conditions, can give accurate computed values for n at downhole conditions.
Determination of Residual Oil Saturation From Time-Lapse Pulsed Neutron Capture Logs in a Large Sandstone Reservoir
Authors: Syed E. U. , Salaita G. N. , McCaffery F. G.
Published: December 2007

Cased hole logging with pulsed neutron tools finds extensive use for identifying zones of water breakthrough and monitoring oil-water contacts in oil reservoirs being depleted by waterflooding or natural water drive. Results of such surveys then find direct use for planning recompletions and water shutoff treatments.

Pulsed neutron capture (PNC) logs are useful for estimating water saturation changes behind casing in the presence of a constant, high-salinity environment. PNC log surveys run at different times, i.e., in a time-lapse mode, are particularly amenable to quantitative analysis. The combined use of the original open hole and PNC time-lapse log information can then provide information on remaining or residual oil saturations in a reservoir.

This paper reports analyses of historical pulsed neutron capture log data to assess residual oil saturation in naturally water-swept zones for selected wells from a large sandstone reservoir in the Middle East. Quantitative determination of oil saturations was aided by PNC log information obtained from a series of tests conducted in a new well in the same field. The tests involved detailed comparative studies between four PNC tools and three different wellbore fluids. Two sets of transforms developed from the above tests provided a means for converting old PNC log data to more current and accurate measurements.

Utilizing time-lapse PNC data, residual oil saturations (ROS) were calculated in swept zone(s) for 22 selected wells. An assessment of the uncertainty in derived ROS values was also made.
Application of Production System Analysis to an Offshore Oil Field
Authors: Ueda Y. , Samizo N. , Shirakawa S.
Published: December 2007

Total production analysis is currently in use in oil field operations assisting the optimization of production to ensure the maximum profitability.

The Khafji Field, being an oil field situated in the offshore Saudi Arabia, has been producing oil from more than 100 wells for the past 30 years. Oil flows from the wellhead jacket to the two-phase separator on the offshore flow station (gas oil separation platform). After flowing to the pump station oil is transmitted through the transmission line to the onshore facilities. Some wells are gas lifted and the production water cut is on the increase. Water cut will definitely intensify with the increase in gas lift operation. The review and evaluation of the offshore facilities, from the individual wellhead to the inlet of offshore separator, is essential so as to optimize oil production.

This paper outlines the field application of production system analysis. The flow through the wellhead choke and the flow through the pipeline have been investigated using actual field data and the technical correlation for these flows have been established. A review discussion is offered concerning the identification of the bottleneck in the existing production facilities which at present time, acts as a serious restraint on oil production. The problems encountered in carrying out this investigation are outlined and, specifically, the solution for the bottleneck problem to optimize production within the limits of existing facilities are discussed at length. Finally guidelines are proposed for future facility design and modification.
Numerical Simulation of Horizontal Wells
Authors: Babu D. K. , Odeh A. S. , Al-Khalifa A. J. , McCann R. C.
Published: December 2007

An analytical equation for calculating horizontal well pressure in a simulation model is derived. This equation is very essential for history-matching and predicting the performance of horizontal wells.

The derived equation is needed to compute the effective radius which relates the wellbore pressure to the wellblock pressure. The equation is general and is valid for vertical and horizontal wells, for any well location and for any anisotropy. This equation may substitute Peaceman's equations which need modifications in anisotropic grids of high aspect-ratio (typical of horizontal wells). Simplified forms of the equation applicable to special cases are also reported.
Cycling Fractured Reservoirs Containing Volatile Oil: Laboratory Investigation of the Performance of Lean Gas or Nitrogen Injection
Authors: Thiebot B. M. , Sakthikumar S. S.
Published: December 2007

A laboratory technique has been successfully developed to perform gas gravity drainage experiments under reservoir conditions in three dimensions, that is on cylindrical cores having both lateral and horizontal faces open to flow.

As an application to a light oil reservoir, a series of experiments has been performed on outcrop cores of various permeabilities, in order to compare the efficiency of methane or nitrogen injection. In a first step, cores were saturated with connate water and volatile reservoir oil and subjected to gravity drainage by injection of a rich gas in thermodynamic equilibrium with the oil phase. In a second step, either methane or nitrogen was circulated around the cores, yielding substantial additional recovery of liquids.

The results obtained clearly indicate that:

– During the first step, recovery was essentially the same as in one dimension experiments (lateral faces coated). – Both methane and nitrogen exhibit fast and complete recoveries of light and intermediate components and appreciable amounts of the heavy end fraction. Kinetics of hydrocarbon recovery is strongly dependant on the nature and the injection rate of the gas injected. – An increase of pressure was investigated during gas injection, which exhibited a favourable effect on the heavier components recovery by methane. This influence was much less pronounced for nitrogen injection.

The laboratory experiments were interpreted with a fully compositional simulator. This confirmed the predominant role of vaporization and molecular diffusion.
Water Quality Requirements for Fractured Injection Wells
Authors: Clifford P. J. , Mellor D. W. , Jones T. J.
Published: December 2007

Field measurements of water quality, together with an assessment of the role of thermally induced fractures, indicate that stringent fine filtration requirements are often not required for water injection wells. Corrosion and scaling of tubulars are shown in some cases to result in a bottom-hole quality worse than raw intake water. Well performance, however, is not seen to deteriorate significantly as a result. The reasons for this are examined by the inclusion of fines in models of injection well fracturing.
Installation and Implementation of a Supervisory Control System
Authors: Pearson W.G. , Troiani L.R.
Published: December 2007

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

The installation and implementation of a large supervisory control system, comprising 500 or more producing wells and ten or more remote telemetry stations, is a major undertaking effecting changes in producing equipment, operating organization and communications. The best approach towards achieving the economic incentives of such a system, smoothly and rapidly, is through detailed coordinating and planning.

Decisions regarding the concepts of installation and operation, plus an approach to the selection of personnel, training of personnel and the development of a working organization are presented. Major problem areas encountered in presented. Major problem areas encountered in the system implementation are presented.

Introduction

It is the intention that this paper be a companion paper to SPE 2143 "Feasibility Study of oil Field Automation." The shaded area of Figure 1 refers to material to be covered by this paper. paper. Who should be responsible for system installation? Once the decision is made to install a large supervisory control system, this is the first major decision to resolve. The initial reaction to this question is almost certain to be somewhat like the following statement. "I think we should find a prime contractor for the project and give it to them on a turnkey basis for we don't have the technical knowledge within our organization to do the job." The reason stated for the conclusion may be true, but following this approach will only lead to trouble.

WHO SHOULD UNDERTAKE SYSTEMS RESPONSIBILITY?

There are four potential sources for the assignment of systems responsibility - the telemetry system supplier, the computer system supplier, a consulting engineering firm, and the company production operating organization. In the cases of the first three, a turnkey contract with a prime contractor is the means to achieve systems engineering for the project. If the company chooses the apparent easy way out by letting a turnkey contract, a number of obvious advantages are obtained as follows:

One or more areas of specific technical knowledge in telemetry systems, computers and computer programming can be manifested within the prime contractor.
Evaluation of Jurassic Arab D Reservoir Quality in Low-Relief Traps in Qatar
Authors: Wilson E. N.
Published: December 2007

This study documents petrophysical changes in the Arab D reservoir in Qatar that affect trap configuration and hydrocarbon accumulation in subtle structures with approximately 100 ft (30m) of vertical relief. Two facies have been identified from well data as capable of sustaining producible oil saturations under these conditions. These are clean grainstones and massive permeable dolomites. Analysis of capillary pressure curves indicates that the interbedded packstones, wackestones and mudstones of the Arab D will act as waste zones with a 100 ft (30m) oil column. The distribution of the highly porous grainstone facies is controlled regionally by paleobathymetry, but is unpredictable from well control on the prospect scale. Areas of high porosity can be identified seismically using acoustic inversions. However, seismic data cannot be relied upon to delineate permeability trends.
Stratigraphy of the Wajid Sandstone of Southwestern Saudi Arabia
Authors: Evans D. S. , Lathon R. B. , Senalp M. , Connally T. C.
Published: December 2007

Until recently, the relatively monotonous, thick sequence of Wajid Sandstone which crops out in southwestern Saudi Arabia has been mapped as a single lithologic unit with a Cambrian-Ordovician age. Seismic ties to the outcrop, recent fieldwork by Bureau de Recherches Geologiques et Mineres (BRGM) and Saudi Aramco' geologists and stratigraphic information obtained from a shallow 2260-foot test well (V-608) suggest that the Wajid Sandstone (as mapped in the outcrop) may be divided into five units and that the rocks range in age from Silurian and older to Permian. From oldest to youngest, the five units are the Saq and Qasim formations undivided (Cambrian-Ordovician age), the Zarqa and Sarah formations (Late Ordovician to Early Silurian age), the Qalibah Formation of Early Silurian age, rocks of Devonian to Middle Carboniferous age undivided, and the Unayzah Formation (Haushi Group) of late Carboniferous to Early Permian age. Except for the Qalibah Formation which is the source-rock of recently discovered oil in the Hawtah, Dilam, Raqhib, Nuayyim and Hazmiyah fields to the north, all of these Paleozoic sands have excellent reservoir potential in the subsurface.

It is proposed that the term Wajid Sandstone be dropped from usage and that the existing Paleozoic nomenclature discussed above and used by Saudi Aramco be applied to the Wajid Sandstone outcrop.
Programming System Development for Supervisory Control Systems
Authors: Zink Jerry L.
Published: December 2007

American Institute of Mining, Metallurgical and Petroleum Engineers Inc.

Flexibility is the key word in selecting the general purpose digital computer for supervisory control systems. The economic objectives of supervisory control are dependent upon utilization of this flexibility in matching the changing conditions of the oilfield. The development of an excellent programming system is vital to utilization of this flexibility.

This paper discusses the steps Continental oil Company uses in developing a programming package for oil production control systems. package for oil production control systems. These steps include:

selecting a central processing unit, fixing the programming processing unit, fixing the programming responsibility, selecting a programming staff, training the programming staff, developing a programming environment, and establishing programming concepts.

Program systems development is dynamic rather than a static process. Therefore, it is likely that many of the ideas presented will be modified as further knowledge and development in the computer control field becomes available.

SELECTING A CENTRAL PROCESSING UNIT

After a feasibility study shows that a supervisory control system should be installed, several important decisions must be made which will affect the growth and operation of the system. The most important of these decisions involves selecting the equipment to be used as the central processing unit.

"Hardwired" or fixed logic units were predominant during the introduction of supervisory predominant during the introduction of supervisory control systems to the oilfield. Later, limited programming capability was added to these fixed programming capability was added to these fixed logic units by means of drum memory. Today the trend is toward the use of a general purpose digital computer as the central processor. The factors influencing this trend are summarized as follows:

The ability to program the logic of the digital computer offers increased flexibility over the "hardwired" unit. Detailed analysis of process variables needed in current systems requires the use of complex logic not available in "hardwired" central units.
Shallow Gas Blowout Kill Operations
Authors: Adams N. J. , Kuhlman L. G.
Published: December 2007

Shallow gas blowouts, as a general class, are the most difficult type of blowout to kill. This paper discusses current industry myths about shallow gas, typical results from a shallow gas blowout that affect the kill operation, kill options and selection criteria, rig selection criteria, and well killing guidelines. The new kill technique of vertical intervention is discussed relative to shallow gas blowouts. Also, a new technique for using horizontal wells in combination with the reservoir flood technique for killing shallow gas, cratered blowouts is explained.
The Impact of Improved Technology on Potential Tight Gas Reserves in the San Juan Basin: A Case Study
Authors: Haas M. R. , Crist T. E.
Published: December 2007

This study evaluates the impact of technology on potential tight gas reserves in the context of current pipeline capacity and project economics. This case study of the Dakota formation is part of a larger analysis of tight sand formations in the San Juan basin, the findings of which are available in a separate report.1

This paper reports the result of a disaggregated appraisal of the remaining Dakota tight gas resource and estimates of gas in place, technical recovery and potential reserves. A location-specific resource database was constructed and typical well recoveries were modeled on a township-specific basis. Project costing and cash flow economics were analyzed to derive potential reserves for various technology specifications and wellhead prices. These data provide a foundation for operators and pipelines to more closely examine the Dakota for development in the near future.

Gas in place for the undeveloped tight portion of the Dakota was estimated at 11.1 Tcf. Potential recoverability with current technology is 4.3 Tcf. Potential reserve additions are 0.6 Tcf at $2.00/Mcf, 1.9 Tcf at $3.00/Mcf, and 3.2 Tcf at $5.00/Mcf. The availability of the Alternative Fuels Tax Credit for certain Dakota wells drilled in the next two years another two years could improve project economics by an equivalent of as much as .88/Mcf at the wellhead.

As part of this study, depth, overburden and isopach maps were prepared and a resource database constructed. The database was analyzed using an integrated recovery and economics model for tight sands that has the capability to do rapid sensitivity analysis of geological, technology and economic assumptions. Although this study has identified the tight sands potential for various areas of the basin, more detailed geologic appraisal and reservoir engineering should be conducted before drilling.
Coalbed Methane Production Potential of the Rock Springs Formation, Great Divide Basin, Sweetwater County, Wyoming
Authors: Young G. B. C. , McElhiney J. E. , Dhir R. , Mavor M. J. , Anbouba I. K. A.
Published: December 2007

Recent development of the Rock Springs Formation in Sweetwater County, Wyoming indicates coalbed methane production potential. Triton Oil and Gas Corp. drilled the #2 UPRC-1 well late in 1989 to test the potential of these coals. An analysis of the data collected indicates that gas content uncharacteristically decreases linearly with depth between 3,400 and 4,000 feet beneath the Triton property, with discontinuities in this relationship occurring both at shallower and deeper ranges in depth. A 25-year prediction of gas producibility for the well using the COMETPC 3-D reservoir simulator indicates approximately 1.0 BCF cumulative gas production or 61% of the gas-in-place for a 160 acre well spacing. These reserves are based only on 14.5 feet out of 36.5 feet of total coal to be completed in the #2 UPRC-1 well. This paper provides some of the first publically available information on commercial coalbed resources in this portion of the Great Divide Basin, part of the greater Green River Basin.
A Reservoir Simulation Investigation into the Interaction of In-Situ Stress, Pore Pressure, and Coal Rank on Coalbed Methane Exploration Strategy
Authors: Reeves S. R. , Decker A. D.
Published: December 2007

Coalbed methane exploration must evolve to adequately reflect a growing geologic and reservoir understanding in domestic and international coal basins. Currently accepted exploration strategies in the San Juan Basin of New Mexico and the Warrior Basin of Alabama are basin specific and remain unproven outside these traditional methane plays. Future development will require modified exploration strategies to locate commercial prospects in the more complex geologic settings of other less favorable domestic and overseas basins. Coalbed methane operators presently focus exploration efforts on locating areas of improved permeability, over-pressured hydrologie conditions, high methane storage capacity coals and a maximum ratio of gas desorption pressure to initial reservoir pressure. The effects of each of these reservoir properties and more importantly their interaction has not been thoroughly examined.

A reservoir simulation study was undertaken to investigate the effects of stress setting as it relates to permeability, pore pressure gradient and coal rank in terms of isotherm characteristics and gas content. A series of 162 well performance simulations were conducted evaluating the interaction of depth, coal permeability in high, normal and relaxed stress settings, gas contents for high, medium and low rank coals and finally, normal and abnormal hydrologie conditions. The results indicate that 1) there is an optimum target depth for a coal of a given rank under a specific stress setting, 2) the optimum producing depth increases with decreasing stress setting, 3) low rank coals exhibit superior production than higher rank coals under similar reservoir conditions and 4) the ratio of desorption pressure to initial reservoir pressure is of less significance than the absolute value of the desorption pressure. Based on these findings, fundamental inadequacies of existing exploration criteria require modification, particularly to the interaction of specific coal reservoir properties.
Analysis of Slug Test Data from Hydraulically Fractured Coalbed Methane Wells
Authors: Rushing J. A. , Blasingame T. A. , Poe B. D. , Brimhall R. M. , Lee W. J.
Published: December 2007

This paper presents new type curves for analyzing slug tests in hydraulically fractured coal seams. The type curves were developed using a finite-conductivity, vertical fracture model and are presented in terms of three parameters – dimensionless wellbore storage coefficient, dimensionless fracture conductivity, and fracture-face skin. With these new curves, we may estimate the hydraulic fracture half-length, the formation permeability, and the fracture conductivity. We also present a procedure for using the new curves and illustrate the procedure with an example.
Using In-Situ Stress and Permeability Thickness Profiles to Design the Well Completion
Authors: Holditch S. A. , Whitehead W. S. , Rahim Z.
Published: December 2007

Most completion engineers use two-dimensional fracture models to design hydraulic fracture treatments. These engineers also use two-dimensional reservoir models to analyze post-fracture production and pressure buildup data. Normally, a completion engineer will concentrate only upon a single zone and will often design a well completion based upon the properties of that zone as computed from log data, core data, drilling data, or other information about the interval.

Once the interval has been evaluated, the completion engineer will pick the location of the perforations based upon the location of the net pay zone. Estimates of porosity, water saturation, and net pay thickness are used to determine where to shoot the perforations and to estimate the value of fracture height that will be input into the two-dimensional fracture design model.

By using a two-dimensional fracture design model, the completion engineer is dictating the fracture height and the fracture shape. If the engineer uses the wrong fracture height, then the calculated values of fracture length and width will also be wrong. Most of the time, an engineer tends to underestimate fracture height and, thus, overestimate fracture length.
Effect of Injected Fracture Fluids and Operating Procedures on Ultimate Gas Recovery
Authors: Sherman J. B. , Holditch S. A.
Published: December 2007

In low permeability gas reservoirs, hydraulic fracturing is often necessary to stimulate gas recovery and provide economic gas flow rates. A hydraulic fracture is created by pumping large volumes of high viscosity fracturing fluid containing a granular propping agent into the formation. The well productivity is improved by creating a highly conductive flow path from the formation to the wellbore. Achieving and maintaining sufficient fracture conductivity is critical to the optimization of gas recovery from hydraulically fractured wells. The purpose of this research is to study how certain factors affect fracture fluid clean-up behavior, well productivity, and ultimate gas recovery from hydraulically fractured wells.

Several studies have been performed to investigate fracturing fluid clean-up behavior and well productivity. A few studies have determined how various parameters affect fracturing fluid clean-up,1–6 while other studies have focused on the factors that affect the productivity of hydraulically fractured wells.7–10 The previous work defined some of the problems associated with the clean-up behavior and well productivity. We have extended the previous work to identify the reservoir conditions that determine how productivity is affected by clean-up behavior.

The objectives of this paper are: (1) to investigate the factors that affect fracture fluid distribution around a fracture; (2) to determine which factors most affect fluid clean-up behavior after a fracture treatment; (3) to quantify the factors that affect well productivity after a hydraulic fracture treatment; and (4) to provide recommendations concerning how to produce a well after a hydraulic fracture treatment to optimize gas recovery. This research was performed as part of the Tight Gas Sands Research Program sponsored by the Gas Research Institute (GRI) in Chicago, Illinois.
Decline Curve Analysis for Variable Pressure Drop/Variable Flowrate Systems
Authors: Blasingame T. A. , McCray T. L. , Lee W. J.
Published: December 2007

The motivation for the work described in this paper arose from a need to analyze production decline data where the flowing bottomhole pressure varies significantly. The variance of the bottomhole pressure with time excludes the use of the exponential decline model for conventional decline curve analysis (semilog plots and type curves). Using pressure normalized flow rate rather than flow rate usually does not remedy this problem. The method we present uses a rigorous superposition function to account for the variance of rate and pressure during production. This function is the constant rate analog for variable-rate flow during post-transient conditions and can be used to develop a constant pressure analog for the decline curve analysis of field data.

The constant pressure analog time function is computed from the constant rate function using the identity that cumulative production for both cases must be equal. Using the cumulative production identity, we solve recursively for the time function using trapezoidal rule integration and, as an alternative, finite difference formulae. We have also developed a constant pressure analog time relation which is rigorous for boundary dominated flow and serves as an accurate approximation for transient flow.

We apply these relations to analytical solutions for verification and then use the boundary dominated flow relation on simulated and field cases. These simulation cases include large and small step changes in bottomhole flowing pressures, and periodic shut-ins. Finally, we apply these relations to a gas well field case.
Non-Darcy Flow Coefficients and Relative Permeabilities for Gas/Brine Systems
Authors: Civan F. , Evans R. D.
Published: December 2007

A method for calculating the effective non-Darcy flow coefficient and relative permeabilities for gas/brine systems is presented. The capillary pressure is considered to account for the end-effect. This method is applicable to linear displacement in laboratory cores.

The computational model was developed by extending the Civan and Donaldson1 model to include the non-Darcy effect and interfacial drag between the gas and liquid phases. For this purpose Darcy’s law was replaced by the Forchheimer equation modified for two-phase systems by Tutu et al. (see Schulenberg and Muller2). Second, a pseudo-pressure formulation was carried out to transform the compressible gas flow and the slightly compressible brine flow equations to incompressible fluid type equations. This serves as a convenience in the calculations. Third, an input-output formulation of the model equations is facilitated for direct calculation of the non-Darcy factors and the relative permeabilities of the gas and the brine phases from the measurements of the pressure differential and the effluent gas to brine ratio. A detailed description of the calculation procedure for implementation on personal computers is presented. Also, the unsteady-state and steady-state differential formulations are developed for comparison purposes.

This method for the calculation of non—Darcy factors simultaneously with the relative permeabilities is essential for the analysis of gas reservoirs involving gas/brine systems. In particular, the simulation of water coning around vertical and horizontal wells where non-Darcy flow may be significant represents an important application of the results presented in this paper.
An Overview of an Instrumented Steam Injection Test Program
Authors: Traynor B. V. , Reid T. B. , Frazier T. R. , Brown V. R.
Published: December 2007

The U.S. DUE has funded a program to "establish a body of valid heat loss data from an active steam injection well". This paper deals with the facilities, instrumentation and data systems required to develop wellbore heat loss information and the test results obtained.

Kawasaki Thermal Systems and Texaco have completed and instrumented a steam injection well in Kern River Field. A casing string instrumented to 800' has been completed. This string includes a total of 18 operational data channels providing temperature and heat flow information. In addition, a 1.9" logging string was attached to the casing as it was run and is used for temperature logs to a depth of 580'. Four instrumented steam injector completions will be operated during the test program.

Tests have been completed with the insulated Injection string. A total of 28 operational temperature and heat flow sensors provided data from this string.

A second instrumented completion, an uninsulated string with five thermocouples and two heat flux sensors has also been tested. These sensors together with the casing instrumentation provided data for this test.

These tests have established data which defines the heat transfer characteristics of the insulated and uninsulated completions. As the program is continued, the data will be utilized to validate a wellbore heat loss model, the final product of the program.
Field Results of Optimizing the Steam Foam Diversion Process in Cyclic Steam Applications
Authors: Cooke R. W. , Eson R. L.
Published: December 2007

Steam foam diverters have been utilized to improve oil production in cyclic steaming applications since 1973. As reservoirs have aged and changed due to substantial oil production from both cyclic steaming and steam drive operations, the development of effective steam foam diversion treatment programs has become more complex.

This paper deals with the development of field application methods to optimize the effectiveness of cyclic steam foam diverters. Actual field results of the applications are described. Various foam diversion treatment methods are outline. Several steam foam diversion agents representing different types of chemical structures were utilized. The oil production responses are reported and the effects of changes in foam diverter type, quantity and method of application are correlated. The economic impact of various application methods, different materials and quantities are reported.
Prediction of Abnormal Pressures in the Niger Delta Basin Using Well Logs
Authors: Owolabi Olubunmi O. , Okpobiri Godwin A. , Obomanu Iyalla A.
Published: December 2007

The hazard associated with abnormal formation pressures are of great concern to operating companies in the oil industry worldwide.

As an effort to alleviate mis problem in the Niger Delta, a spread of overpressures as they occur in the basin are shown in a map of the area. The table from which the map was produced contain the values of the top of overpressures obtained from shale resistivity, acoustic and resistivity plots against true vertical depth. The depth to the top of overpressures from the more than 230 wells studied, range from 6,500ft. along the shelf, to 15,000ft. at the middle belt and 16,000ft. at the west-belt of the Niger Delta Basin Complex.

Shale resistivity ratios and shale transit time differences obtained from normal and observed (abnormally high pressured) resistivities and transit times respectively, have been used in conjunction with the fluid pressure gradient, to generate the prediction curves. Comparison is made between the predicted formation pressures using the predicted curves and actual measured pressures. The standard deviation for the resistivity method is +0.626% psi/ft. (or about ±63 psi per 10,000ft.) and the acoustic method is ±2.058% psi/ft. (or about ±200 psi/ft. per 10,000ft.) Using data from previously published papers, correlating equations for predicting formation fluid pressure gradient are presented for some other major producing areas.
A Laboratory Study of Natural Gas Huff ‘N’ Puff
Authors: Haines Hiemi Kim , Monger Teresa G.
Published: December 2007

This paper examines the feasibility of cyclic natural gas injection for the enhanced recovery of light oil from waterflooded fields. Approximately 40 percent of water-flood residual oil was recovered in corefloods using two huff ‘n’ puff cycles at immiscible conditions. Gross gas utilizations were as low as 3 MSCF/STB. Response to cyclic injection contrasted favorably with immiscible WAG displacement. Coreflood results and numerical simulation indicated that incremental oil was not highly sensitive to remaining oil saturation. Predicted field recovery could be improved by managing offset wells. Response to cyclic gas injection was mostly dependent upon the amount of gas injected, suggesting that there will be a maximum economic slug size in field applications. Results indicated that repressurization and gas relative permeability hysteresis are the major oil recovery mechanisms.
A Robust Algorithm for Determining Hydrocarbon PVT Properties Using A Generalized Eos
Authors: Guehria Fawzi M. , Thompson Leslie G. , Reynolds Albert C.
Published: December 2007

This paper presents and discusses a complete phase behavior package for determining PVT properties of mixtures of hydrocarbon and non-hydrocarbon species commonly encountered in the Petroleum Industry. All calculations are performed using a generalized Equation Of State, which upon selection of appropriate parameters, can be used to represent any of five Equations Of State commonly employed in the Petroleum Industry; i.e., Redlich - Kwong, Zudkevitch - Joffe - Redlich - Kwong, Soave - Redlich - Kwong, Peng - Robinson and Schmidt -Wenzel.

A robust algorithm, which utilizes a combination of the modified successive substitution and Minimum Variable Newton-Raphson methods, is used to calculate flash composition and saturation points. The algorithm is optimized to facilitate convergence near the critical point. The modified successive substitution method is used to determine the number of phases present at a given pressure and temperature. A new simple method is used to ascertain whether the system temperature is greater or less than the critical temperature. The method does not require estimation of the critical temperature for the specified mixture. Straight forward application of a method proposed by Baker and Luks allows the user to efficiently compute all saturation points (i.e., a bubble point and a dew point, or, an upper dew point and a lower dew point) at a given value of temperature. This latter unique feature enables the user to define the two-phase envelope without having to perform a multitude of time consuming flash calculations. Finally, results from our phase package are compared to those presented previously in the literature in order to verify the accuracy and efficiency of the computational procedure.