bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evolution of Reservoir Simulation for a Large Carbonate Reservoir
Authors: Al-Dawas S. M. , Krishnamoorthy A. M. 
Published: December 2007

ABSTRACT
Reservof-1 is a large carbonate reservoir that was discovered and developed in the 1940's. A brief description of the reservoir and major events of the field development are presented.
A 2D areal model was constructed for the reservoir in the 1970's. The use and the shortcomings of the model are discussed.
A 3D model was constructed for the reservoir in the 1980's. The justification for the construction is outlined. The utilization of the model is presented with some examples,
Reservoir-II underlies reservoir-I and both are in communication through fractures in the intervening formation. A model combining both of the reservoirs was constructed. The use of the model to investigate the effects of the communication, and depletion of reservoir-II is discussed.
For all the above models, a separate coarse grid 2D aquifer model is used to generate fluxes to simulate aquifer support. A recent software development (Locally Refined Grid) allowed the 3D fine grid model of reservoir-I to be embedded in the 2D aquifer model. The experience with the LRG model is discussed.
The computer resource requirements for all the above 4 models are displayed, showing increasing requirements with complexity. The concept of multiple model utilization is presented.
Conclusions based on model utilization, resource requirements and expectations, are presented.
Estimating Formation Permeability and Producibility in Oil-Based Mud Using the EPT
Authors: El Shafei I. , Zaki M. , Andreani M. 
Published: December 2007

Abstract
Most mathematical correlations to determine permeability consider porosity (Ø) and the irreducible water saturation (Swirr). Porosity is a function of the number of channels conducting fluid, while Swirr relates to the geometry of these channels - to their radii in particular. It has long been recognized that permeability is related to the grain size and compaction of a system, and to the channel path tortuosity. As the grain size increases, there is also an increase in pore radius and a corresponding decrease in surface area. This decrease in surface causes a decrease in the irreducible water value. Thus, changes in Swirr can be used as indirect measurements of grain size variations. Therefore, a value of Swirr is necessary in order to determine permeability from any of the standard mathematical correlations.
In an oil-bearing zone, Swirr can be determined from the deep resistivity measurement, Rt. However, to accomplish this, representative values of the porosity and saturation exponents (m and n) are needed. In water-bearing and transition zones, classical resistivity measurements cannot be used to determine Swirr.
The introduction of electromagnetic propagation measurements in the invaded zone has opened new avenues for determining Swirr in both oil and water-bearing formations. As the oil based mud invades the formation, the oil will displace the moveable water in the invaded zone leaving only the irreducible water. These electromagnetic measurements also provide the additional advantage of eliminating the need for values of m and n.
This paper considers permeability evaluations made using the Electromagnetic Propagation Tool (EPT*) in oil based mud environments. The computed permeability values were used to estimate formation injectivity and producibility and to optimize the completion program, and were found to compare very favourably with test and production data. This technique was used successfully to identify high permeability streaks and impervious formation layers.
Stimulation of Two Adjacent Dolomite and Sandstone Layers in the Sahmah Field
Authors: Al Bussaidi S. , Champetier J-L. , Lassus-Dessus J. 
Published: December 2007

ABSTRACT
After production from the lower HAUSHI reservoir of the SAHMAH field (SULTANATE OF OMAN) to its high water cut limits, wells were completed In the upper HAUSHI. The proven reserves of the upper HAUSHI reservoir are shared between two adjacent layers, a dolomitic drain overlain by a sandstone level. Added difficulty is that the reservoir is deep (3250 m, 10700 ft), hot (120 C, 250°F) and partially depleted.
The optimization of the stimulation design and its Implementation on the field are crucial in this tight oil bearing formation. Procedures and field results of a typical design are presented. Formation rock properties of the pay zone and adjoining barriers were determined from core samples and sonic log analysis. The fluid and proppant selection were based on laboratory experiments. A 2D-frac simulator was used to optimize the size of both acid and propping treatments.
First, an acid treatment was conducted on the dolomite. Significant rig time was saved by using a new method of temporarily sealing the dolomite zone. Next, a minifrac job was performed on the sandstone.
The results of the minifrac were used as a calibration for the design of the final frac job and to adjust the propping treatment. After hydraulic fracturing, economic production rates were obtained from the upper HAUSHI.
Chief technical contributions: Detailed description of a successful hydraulic stimulation and field results for a reservoir having adjacent dolomite and sandstone layers.Use of mlnlfrac as a decision tool to evaluate the feasibility of the propping treatment to be used on the sandstone level.Optimization of diverting techniques to save rig time.
Permian Khuff in Abu Dhabi: Geological Re-Evaluation Using Well Logs, Cores, Testing, and Seismic Data
Authors: Loutfi G. , Hamd M. Abul 
Published: December 2007

Abstract
The Permian Khuff Formation in Abu Dhabi has been the subject of a thorough re-evaluation of all available data to ensure that the gas resources of this major reservoir sequence are well defined and optimumly exploited. The Khuff is one of the most complex carbonate reservoirs in the Middle East, with vertical variations in lithology, pore volume and types, and fluid content. Over the years there has been major changes in the technology used and, thus, also in the quality of the data acquired - some of which were obtained more than ten years ago.
The complex Khuff pore systems and the initial estimates of their producibility are defined by a thorough integration of core and log data. The most detailed analysis was performed using cores, but as this data is not available for many producing zones it was necessary to employ other data. A combined geological and petrophysical data base allowed interpretation modelling of log data, for zones which were not cored. No unique porosity/permeability relationship can be defined for the Khuff reservoir zones as they vary in character, so a data base approach was used to determine the permeability in each of the Khuff wells investigated in this study. A significant improvement in the saturation and calculation of matrix permeability was made by realistically defining Archie's "m" exponent - especially in zones with secondary porosity.
Fractures play an important role in determining the permeability of the Khuff reservoirs. The evaluation of fractures was carried out by integrating logs, borehole imagery, core data, pressure tests and well tests. Most of the highly fractured intervals are within the low porosity dolomite zones which were not completely cored. Calcitic and/or anhydritic zones had poorer reservoir fractures because fewer fractures were developed and because of the pervasive cementation of fractures by anhydrite in anhydritic zones.
Seismo-stratigraphic re-evaluation was initiated to determine seismic criteria of the Permian Khuff reservoirs, and ultimately, to document seismic signature (finger prints) for the Khuff Gas Zones. A fully integrated study, comprising interpreted open hole logs. Check Shots Surveys, Synthetic Seismograms, production data and seismic sections was conducted. Results were encouraging. Further investigations are however, required.
This multidisciplinary study has advanced the understanding of the Khuff reservoir zones in Abu Dhabi and has improved the evaluation approach for new wells.
Optimized Completion Significantly Reduced Cost and Time in Gulf of Suez Fields
Authors: Mansour S. , Khalaf F. 
Published: December 2007

Abstract
This paper presents the chronological development of Gulf of Suez Petroleum Co. (GUPCO) offshore well completions. Reservoir depletion and the problems experienced with the initial completions prompted the need for basic changes. Several changes in completion systems were studied before an optimum solution was selected. The development includes all the areas of original completions that had shown operational shortcomings: the completion-fluids design and selection, down hole equipment, running and pulling operations, wireline phase, perforating, and initial flow phase. All the changes interacted and resulted in the completion optimization which have considerably reduced operations time and cost, significantly reduced operational problems, and increased well productivity. It worth to note that, as a result of completion optimization, now a completion job takes less than one half of the time that was spent to complete one well ten years ago.
Resolution of Fault Block Communication Leading to an Optimal Plan of Depletion, Abu Gharadig Gas Field, Egypt
Authors: Lachance D. P. , Rezk A. S. 
Published: December 2007

Abstract
This paper describes the successful determination of the existence and degree of communication between gas reservoirs in adjacent structural fault blocks in a field in western Egypt. The method used was the comparison of volumetrically determined gas in place with material balance determined gas in place. Individual well performance data were merged to show the existence of pressure communication between wells and between fault blocks.
3-D Seismic Data Analysis of Late Cretaceous and Tertiary Velocity Anomalies in Northeastern Saudi Arabia
Authors: Snell G. W. , Airey J. T. 
Published: December 2007

ABSTRACT
Velocity anomalies attributed to Late Cretaceous and Tertiary solution collapses have hindered the exploration for low-relief structures in Northeastern Saudi Arabia. Complex time distortion in key seismic horizons is often associated with collapse features and accompanying fracturing and secondary mineralization. It is often difficult to distinguish real low-relief structure from velocity-induced anomalies with conventional 2-D seismic control, which provides united subsurface coverage. A 3-D seismic survey was acquired near Kurayn Island in an attempt to develop seismic processing and interpretation criteria to resolve velocity-induced time anomalies. Previous seismic work showed this area contained numerous solution collapse features.
The dense subsurface coverage provided by 3-D seismic data exposed the high spatial frequency and complexities associated with collapse features. Parameters determined by analyzing spatial and time relationships of collapse features in this area can be applied to resolving similar problems throughout the region.
Preliminary Investigations Into Possible Stratigraphic Traps, Offshore Abu Dhabi
Authors: Azer S. R. 
Published: December 2007

ABSTRACT
During the last three decades, exploration efforts in offshore Abu Dhabi were mainly focused on the search for the more common (in the Arabian Gulf) conventional type structural trap. The existence of stratigraphic traps in offshore Abu Dhabi is possible and the deliberate exploration for those more difficult subtle traps is demanding.
So far in offshore Abu Dhabi, the Mishrif is the only formation which was given special attention for possible stratigraphic traps.
The main objective of this paper is to highlight the possibility of stratigraphic traps in formations other than the Mishrif. It is not meant to delineate or pin point locations of certain stratigraphic traps, but to put things in perspective regarding these traps. The approach is to establish general models of stratigraphic plays of different kinds in various reservoirs, which could be applied to offshore Abu Dhabi. These models are a starting point and would be pursued in greater detail at a later stage in collaboration with seismic modelling.
Examples from the Lower Cretaceous Thamama, and Jurassic Arab, Diyab and Araej formations are considered.
The traps most likely to occur in offshore Abu Dhabi are mainly updip porosity pinchouts, diagenetic and unconformity traps.
Geological Model and Reservoir Evaluation of the Lower Cretaceous Bab Member in the Zakum Field, Abu Dhabi, U.A.E.
Authors: Aldabal M. A. , Alsharhan A. S. 
Published: December 2007

ABSTRACT
In the Zakum Field, the Shuaiba Formation (Aptian) is the upper most rock unit of the Lower Cretaceous Thamama Group, in ascending order it is divided into three zones, Thamama IA, IB and IC. The last two have been termed the Bab Member, has an average thickness of about 230 ft. and shows a diverse lithology. Minor changes in eustatic sea level at the time of deposition produced a major change in the lithofacies distribution across the field. These range from deep water basinal to shallow shelf sediments.
The lower part of the Bab Member (Thamama IB) is divided into three: A progradational carbonate cycle of deep water argillaceous globigirinal limestone at the base (Tar Unit), which could represent a good source rock. Above it are drowned shelf sediments of bioclastic wackestone with a moderately developed reservoir facies (IX unit). These end with a highly dolomitized unit of poorly developed reservoir facies, which forms a comparatively good seal.
The upper part of the Bab Member (Thamama IC) consists of calcareous shale interbedded with limestone of good reservoir quality. The limestone is separated into two reservoir facies units (IT & IW) and is well developed in the East, representing a shallow shelf to high energy shoal deposits (oolitic grainstone, calcareous algae, orbitolinid and skeletal debris). These sediments were transported westward and deposited over the slope of the deeper water environment and limiting the reservoir facies to the crest and eastern flank of the field.
In order to evaluate the economic potential of the sequence, all of the possible reservoir units were defined using wireline logs and petrographic description.
Facies units (IT, IW & IX) were mapped over the field. Units IT & IW represent a stratigraphic trap, with some later influence of structural uplift due to deep seated salt piercement. The oil accumulation in the reservoir units is restricted to the shelf and shelf edge facies. The tilted oil/water contact (OWC) is a pronounced feature of the field.
The prolific cyclic carbonate sand facies (IT & IW) as part of abroad carbonate shelf platform extend further East of Zakum Field. Subsequently, development of reservoir quality connot a potential future prospect.
Oil Prospectivity of the Khuff Formation in Oman
Authors: Abu-Risheh A. , Al-Hinai K. B. M. 
Published: December 2007

Abstract
The Khuff formation has been known to contain gas bearing reservoirs in several fields in the Gulf states. With the discovery of oil in this formation in the Yibal field in 1986, the Khuff carbonates have been given increasing attention and became a significant target for oil exploration in Oman.
While a number of the sedimentological and geochemical aspects of the Khuff have yet to be analysed, the earlier model of a generally uniform depositional sequence is still being regarded as correct.
The oil prospectivity of the Khuff reservoirs lies in the various elements of its deposition, diagenesis, burial depth and the geometric relationships between this formation and underlying sources of hydrocarbons. The basal and pre-Khuff erosional or nondepositional unconformities may have played a significant role in charging the reservoirs.
Generation, Migration, and Transportation of Gas-Contaminated Regions of Drilling Fluid
Authors: Casariego V. , Bourgoyne A. T. 
Published: December 2007

ABSTRACT
This paper presents a new method to predict both gas velocity and gas concentration for processes of well control operations in vertical or near vertical wells. The effect of gas concentration on gas velocity is taken into account. The dispersion of the gas-contaminated region of drilling fluid with time can be determined for both static and circulating well conditions.
The method was integrated into an existing well control simulator computer program. The improved numerical model closely predicted measured casing pressure profiles that were obtained in a 6000-ft research well.
The Optimization of the Red Oak Infill Drilling Program in the Arkoma basin
Authors: Flournoy C. M. 
Published: December 2007

ABSTRACT
Amoco Production Company has drilled 47 wells in the Red Oak Field since the fall of 1985. During this time, average drilling times and well costs have been reduced approximately 45 percent through the optimization of both air and mud drilling practices, a streamlining of casing programs, and an increased ability to avoid downhole problems. The keys to the optimization process have been extensive post-appraisals of offset wells and thorough planning of each upcoming well, coupled with aggressive wellsite supervision during the drilling process. The result has been a fairly simple drilling plan with emphasis on the consistent execution of basic drilling practices.
A Case History: Inhibitive Drilling Fluid System and Large Cutter PDC Bit Usage Reduce Overall Well Cost and Drilling Days
Authors: Allen M. K. , Wampler C. W. 
Published: December 2007

ABSTRACT
The utilization of an inhibitive mud system coupled with the use of Large Cutter Polycrystalline Diamond Compact (PDC) bits reduced overall well costs by 47.6% and similarly reduced drilling days by 57.7% when compared to the seven previous wells drilled from the same platform. This trouble-free well was drilled in Block 557, West Cameron, Louisiana and shows the benefit of proper drilling fluid and bit selection.
The design of the drilling fluid was predicated on the use of a partially hydrolyzed Polyacrylamide (PHPA) functioning as a protective colloid. The PHPA reduces the surface reaction of the drill cuttings which limits their hydration and dispersion. This drilling fluid system, combined with the optimization of hydraulics, eliminated bit balling and provided a stable wellbore while drilling highly reactive gumbo. As a result, the Large Cutter PDC bit selected was able to drill in the proper shearing mode and penetration rates were maximized.
The West Cameron area is categorized as a difficult location in which to drill due to the extremely reactive shales encountered. The frequency of stuck pipe that occurred on the previous wells was eliminated and was attributed to the thin, compressible filter cake and excellent hole cleaning provided by the PHPA drilling fluid. Study of the filter cake compressibility ratio at the drilling site was used to monitor cake quality.
Comparison of the over-all well costs, drilling days, rotating hours, and number of bits used on the subject well versus the seven offsets defines a "learning curve" which should be considered when drilling future wells.
Extensional Viscosity Effects in EOR
Authors: Jones D. M. , Walters K. 
Published: December 2007

ABSTRACT
Evidence is first advanced that some polymeric displacement fluids of potential use in EOR experience abnormally high resistance in extensional flows. Since flow through a porous medium involves a substantial extensional flow component, it may be argued that there is justification for studying the effect of this high extensional-viscosity behaviour in a number of idealized geometries of relevance to EOR conditions. The resulting experiments indicate that, at low flow rates, shear viscosity is the dominant influence, but that, after a critical set of conditions are attained, extensional-viscosity considerations become all-important and the observed pressure losses are against any expectation based on conventional fluid mechanics. The relevance of these critical conditions, after scaledown, to practical porous medium flow is under active consideration.
Flow visualization studies support the pressure drop measurements in emphasising the strong influence of high extensional viscosities in flows through tortuous geometries.
Evaluation of Volumetric Conformance for Fenn-Big Valley Horizontal Hydrocarbon Miscible Flood
Authors: Asgarpour S. S. , Todd M. R. 
Published: December 2007

ABSTRACT
Many experimental and mathematical studies of volumetric conformance in a miscible flood have been presented in the literature. However, little attention has been paid so far to the field evaluation of volumetric conformance.
In the Fenn-Big Valley hydrocarbon tertiary flood, several techniques and a simulation study have been used to evaluate volumetric conformance. Nine water and gas tracers were injected early in the life of the tertiary flood to trace the movement of both injected water and solvent. The results of the tracer tests along with Bi-weekly compositional analyses of produced fluids and field measurement of viscosity provided valuable information.
A reservoir simulation study served as a tool to describe the interaction of the miscible flood process and the reservoir geology. The historical performance of the primary natural water drive and the first five years of solvent injection were reproduced with a fair degree of accuracy by a simulation model of one pattern element within the project area. The miscible flood description which resulted in the best fit of the observed pattern flood performance depicts a displacement that is characterized by modest viscous instabilities and gravity override.
Examination of BHTV, FMS, and SHDT Images in Very Thinly Bedded Sands and Shales
Authors: Hackbarth C. J. , Tepper B. J. 
Published: December 2007

ABSTRACT
Three logging tools can produce detailed images of the wellbore wall, based upon variations in rock properties: the Borehole Televiewer (BHTV), an acoustic device, and the Schlumberger Stratigraphie High-Resolution Dipmeter (SHDT) and Formation MicroScanner (FMS), electrical tools that measure relative formation resistivity.
A Shell well was cored and then logged with the BHTV, SHDT, and FMS tools. The rocks consist, in part, of thinly interbedded sands and shales, with bed thicknesses down to 1 mm thick.
The log and core data from this well were rigorously compared to the images generated by the BHTV, SHDT, and FMS tools. We conclude that the BHTV, SHDT, and FMS produced good images of the interbedded sands and shales down to a bed thickness of about 1.5 inches [38 mm]. Below 1.5 inches [38 mm], the SHDT image showed closer to the true number of very thin beds present. Overall, the BHTV amplitude data gave the best sense of actual sand:shale ratio; the FMS images were slightly less similar to the core, compared to the BHTV and SHDT. All three tools are influenced by very small changes in borehole size. Heavily cemented zones are easily detected by all three tools. None of the three tools produced an accurate image of slumped silty shale or homogenous-looking silty shale, possibly due to irregular borehole washouts.