bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Delineation and Development of the Gas Council/Amoco Group North Sea Leman Field
Authors: Cole Ronald J. , Marshall Charles R. 
Published: December 2007

Introduction
The Leman field was discovered by the Shell/Esso group in March, 1966, when they drilled their initial exploratory well in the British North Sea approximately 60 miles NNE of Great Yarmouth, England. This discovery well found 900 ft of Rotliegendes sandstone at a depth of approximately 5,900 ft subsea. The well was initially tested at a flow rate of 25 MMcf/D in June of 1966. Daring June, 1966, the Gas Council/Amoco Group moved a jack-up type drill barge into U.K. North Sea Block 49/27 and spudded a field confirmation well 5.5 miles ESE of the Shell/Esso discovery well. This well was ultimately completed in Sept., 1966, and tested at a rate of approximately 25 MMcf/D.
Subsequent delineation drilling by the Shell/Esso Group, Mobil, Arpet Group, Phillips, Signal and the Gas Council/Amoco Group has now established that the Leman field is just over 20 miles long and 8 miles wide at its center covering an area of about 65,400 acres or 102 sq miles as shown in Fig. 1. The Rotliegendes sandstone which makes up the pay interval in the Leman field is of Early Permian age and is encountered at a subsea depth of approximately 6,000 ft. This sandstone is thought to have been originally deposited by swift flowing streams on alluvial desert plains and later reworked by wind into dunal-type deposits.
The Leman field structure is basically a faulted anticline with a gross Rotliegendes sandstone thickness of 800 to 1,000 ft. The faulting apparent in the Leman field is of a tensional nature, but because of the great thickness of the reservoir zone, the faults do not appear to be sealing. The complete Rotliegendes sandstone appears to be composed entirely of sand with a great variation in grain size distribution. No continuous impermeable layers or shale breaks are apparent in the Rotliegendes section, and the net gas productive sand section is normally the gross sand productive sand section is normally the gross sand section found above the water level.
The wide variation in porosity found in the Rotliegendes sandstone is attributed to the dunal-type deposition of the sand. The dunal working of the sand leads to the creation of areas where very fine grained sand has accumulated, thus creating areas of very low porosity and permeability. As a general trend, it has been noted that normally the highest porosity within the Rotliegendes pay section occurs at the crest of the Leman field structure. Also a porosity trend is noted along the major axis of porosity trend is noted along the major axis of the field with lower porosity and permeability being found in the northwest sector of the field.
Biodegradation Studies of Saudi Arabian Crude Oil
Authors: Whiteside S. E. 
Published: December 2007

Abstract
A bench-scale aerobic microbial degradation study of soil contaminated with Saudi Arabian crude oil was conducted. The effects of nutrient additions and seeding with naturally-occurring microorganisms were evaluated, through comparison of results from a control reactor, a second reactor with nutrients, and a third reactor with nutrients and seed microorganisms. A separate weathering experiment was conducted under identical environmental conditions for evaluation of abiotic weathering losses of crude oil.
The total petroleum hydrocarbon (TPH) content of soil contaminated with crude oil was measured as a function of time. During the five-week evaluation period, a TPH reduction of 60 to 70% was observed for the nutrient evaluation. Based on the weathering tests, approximately 17% of the TPH loss was attributed to abiotic losses.
For the specific environmental conditions, crude oil, seawater, and soil evaluated, the addition of nutrients stimulated the biodegradation of crude oil over the test period. Due to the availability of indigenous bacteria, seeding with naturally-occurring bacteria did not improve the rate of TPH loss.
Total Quality Management for the Oil and Gas Industry
Authors: Kessler F. A. 
Published: December 2007

Abstract
Total Quality Management (TQM) is applicable to all oil and gas companies, including majors, independents, and service companies. Presented here are an overview of TQM, a brief history of TQM in Japan and in our industry, a report on Japan’s oil and gas industry plans and progress, a discussion of the benefits of adopting this new management system, and a description of what is required to implement it. Examples of productivity and profitability improvements, as well as additional opportunities for improvement, are used to demonstrate the applicability of TQM to our industry. Calculation of potential profit improvements averaging three times current profit levels are used to illustrate the potential financial impact of this new management system to our industry.
Pitfalls in the Fractal Analysis of Reservoir Property Data
Authors: Gray T. A. , Chork C. Y. , Taggart I. J. 
Published: December 2007

ABSTRACT
This study finds that three commonly used techniques for estimating the fractal dimension of one-dimensional records are not reliable when the underlying fGn signal is either limited, non-Gaussian or non-stationary. The three techniques are the rescaled range (R/S), variogram and spectral methods. Techniques which transform raw data into Gaussian and stationary data sets for more reliable parameter estimates are presented and illustrated with log data.
Russian Lateral (BKZ) Analysis
Authors: Wiltgen N. A. , Truman R. B. 
Published: December 2007

Abstract
This paper covers the essentials of the tools, and practice of basic Russian well logs and Russian log analysis techniques. Emphasis is placed on those tools used in Russia which are significantly different than their counterparts in other major petroleum producing provinces.
The BKZ Kapotax is five Russian lateral electrical resistivity logs run at different spacings depending on the reservoir thickness. It is used to calculate true formation resistivity. The technique corrects for mud and borehole effects using response curves modeled for a lateral log. This technique uses different tool spacings, borehole size, mud resistivities, diameter of invasion and the resistivities of the five laterals.
This paper presents the BKZ method for predicting the true formation resistivity from this combination of lateral logs. Laterals were the primary resistivity log recorded by Russians before the early 1980’s. Now the induction conductivity log is also being used, but not in the BKZ technique for determining Rt. Only lateral devices are used for this determination.
By using the BKZ method, quantitative information may be extracted from historically recorded data and allows improved evaluation of reservoirs in previously drilled wells.
Application of Siliciclastic Sequence Stratigraphy to Exploration: Examples From Frontier and Mature Basins
Authors: Bowen D. W. , Weimer Paul , Scott A. J. 
Published: December 2007

Abstract
The application of sequence stratigraphic concepts has led to both successes and failures in petroleum exploration. A broad spectrum of reservoir occurrences are predicted in siliciclastic sequence stratigraphic models. The most successful applications have been in turbidite systems (lowstand systems tract) and incised valley-fills (lowstand and transgressive systems tracts). We analyze one example from each of these depositional settings which helps point out the successes and limitations of sequence stratigraphy in exploration of both frontier and mature basins.
The first example is from the Lower Cretaceous turbidite systems of the Bredasdorp and Pletmos basins of offshore South Africa. Exploration in these basins by Soekor (Ltd.) Pty demonstrates the frontier exploration applications of sequence stratigraphy. Basin-floor fans and basin-floor channel fill targets had 30% (14 wells) success ratio, whereas slope fan and prograding complexes had only one success. Drilling in the adjacent Pletmos basin had no success in five wells that targeted lowstand turbidite systems.
The Pennsylvanian Morrow Formation of eastern Colorado is the second example analyzed and demonstrates the application of sequence stratigraphie concepts in a mature basin. This is an incised valley-fill play that produces from several different valley-fill systems. Of the 181 wells drilled along a single valley-fill trend, 41.4% of the wells penetrated the valley (75 wells), 19.3% of the wells found reservoir quality sandstone (35 wells), and 9 new fields were discovered (5% rate of success). Since 1985, when the play was interpreted as an incised valley-fill, drilling statistics indicate that there was no significant increase in the success rate of discoveries, even though a greater percentage of wells penetrated valley-fill facies. This case study indicates that the major problems in valley-fill exploration were 1) locating the valley, 2) locating reservoir sandstone within the valley, and 3) finding a trap for the reservoir.
These drilling results indicate that sequence stratigraphy helps in exploration by defining play boundaries and prospects. However, they also suggest that the application of sequence stratigraphie concepts may not directly result in an increase in the rate of success of individual prospects. Sequence stratigraphie analysis only addresses the reservoir, source, and seal components of the petroleum system. Trapping mechanisms still remain a significant source of risk.
Fanlobe Geometry and Reservoir Sand Characteristics of Ram/Powell Field, Deepwater Gulf of Mexico
Authors: Clemenceau G. R. , Miller P. L. 
Published: December 2007

Abstract
Ram/Powell is one of the largest Deepwater Gulf fields discovered to date. The geologic model describing this field is based upon an interpretation of well, core and 3-D seismic data. The reservoirs are trapped within the turbidite sands of a Miocene deep-sea-fan. This fan is composed of multiple fanlobes which have seismic reflectors of varying amplitude and internal/external configuration. Individual fan lobes have elongate lens-shaped geometries which pinch-out updip and laterally, forming a stratigraphic trap. Amplitude and isopach maps display sinuous trends, sub-parallel to lobe axes, which are interpreted as turbidite channel/levee deposits. Sands associated with these channels are massive and have excellent reservoir characteristics. Thin-bedded levee/overbank turbidites encountered contain good quality reservoir sands.
Numerical Simulations of How Cap-Rock Properties Can Control Differential Entrapment of Oil
Authors: Rostron B. J. 
Published: December 2007

Abstract
The theory of differential entrapment of hydrocarbons, proposed by Gussow almost 40 years ago, has been used to explain the basin-wide distribution of oil and gas in reef trends. However, reef trends with hydrocarbon distributions different from the predicted distributions can be found. To date, there are no widely accepted explanations for these differences. In order to explain these discrepancies and better understand differential entrapment, a series of numerical simulations of oil migration in a reef trend were conducted.
Results show that the hydraulic properties of the system control oil migration and entrapment. If the cap-rocks are assumed to be impermeable (consistent with the original theory), then the spill point controls the height of oil column in the trap, and the position of the trap within the trend controls the type of hydrocarbon present. If the cap-rocks have some permeability, then entrapment is controlled by the interaction of the "sealing" properties (capillary pressure curves and permeability distribution) and the "leaking" properties (fluid density and formation-fluid gradients) of the system. Simulations illustrate that with certain cap-rocks it is possible to have traps that cannot be filled to their spill points.
A better match could be obtained between observed and predicted distributions of hydrocarbons for the entire trend if the model of differential entrapment is expanded to include the cap-rock properties of each reef.
Pressure-Transient Analysis for a Well With Multiple Horizontal Sections
Authors: Kamal M. M. , Buhidma I. M. , Smith S. A. , Jones W. R. 
Published: December 2007

ABSTRACT
Available pressure transient solutions assume that the entire horizontal well section is contributing to flow. Analysis of transient tests using these models result in unrealistic values for permeabilities and skin. Production logging of such wells also indicates that only certain intervals are productive. This is probably the result of heterogeneity (e.g. the presence of fracture swarms) or damage. To solve this problem, engineers use an effective horizontal well length which is shorter than the actual horizontal well section. This however, does not reflect the actual flow configuration, since it assumes that the effective length is a contiguous section.
In this paper we show the effects of using too long a production interval on the interpretation of test data by analyzing numerically simulated tests from wells that are only partially open to flow in the horizontal section. We show how the values of horizontal permeabilities, vertical permeability, and skin are affected. We then present an analytical solution that allows for a well to consist of a number of segments of arbitrary length, strength, and skin. We use this model to document the effect of neglecting the actual flux distribution and well length on the results of the well test interpretation. A new radial flow regime is identified from the results of the segmented horizontal well model. It results in a flat pressure derivative at a value of 0.5 divided by the number of producing segments. We also use this model to analyze actual cases where pressure transient and production logging are available. This analytical model is also useful in handling dual lateral completions.
We show that the use of incorrect horizontal well length or flux distribution can lead to estimating erroneous well and reservoir parameters from pressure transient tests. We show actual production logging data that demonstrate the variation of the contribution from different sections of the horizontal well. The model presented in this paper enables the engineer to combine production logging data, or any other information that indicate the possible distribution of flow in a horizontal well, and pressure transient data to obtain more realistic well and reservoir parameters.
Use of Porosity as a Strength Indicator for Sand Production Evaluation
Authors: Sarda J-P. , Kessler Nicolas , Wicquart Emmanuelle , Hannaford Kevin , Deflandre J-P. 
Published: December 2007

Abstract
Production history, fluid pressure and uniaxial compressive strength are basic data to evaluate the risk of sand production. Evaluations of the compressive strength based on logs are illustrated for the example of a well on the Germigny-sous-Coulombs structure. Then relationships between compressive strength and porosity are developed using a theoretical approach of grain contacts, the analysis of published rock mechanics data and mechanical measurements on plugs taken from well cores. It is shown that compaction factor can complement porosity in the analysis. A field example illustrates the relationship between a critical differential pressure and compaction factor or porosity.
Determination of Reservoir Permeability Distributions from Pressure Buildup Data
Authors: Feitosa G. S. , Thompson L. G. , Reynolds A. C. 
Published: December 2007

Abstract
This work focuses on the analysis of pressure buildup data obtained at a well at the center of a cylindrical reservoir in which the absolute permeability is a function of distance from the well, i.e., is a function of the radial coordinate. It is shown that the permeability distribution can be estimated directly from pressure buildup data by application of an inverse solution algorithm. For cases where permeability is a function of both r and θ, it is shown that our inverse solution procedure yields an "equivalent" radial permeability distribution. It is also shown that the reservoir pressure profile at the instant of shut-in can be approximated from the buildup pressure data.
Finally, we discuss briefly, the stabilized inflow performance relations for a well producing from the center of a cylindrical heterogeneous reservoir.
Well Test Interpretation in Geologically Complex Channelized Reservoirs
Authors: Massonnat G. J. , Norris R. J. , Chalmette J. -C. 
Published: December 2007

Abstract
The interpretation of pressure transients by the use of analytical models generally leads to a simplified description of the geological heterogeneities around the well. Although this approach works when the geology is simple, clearly, more complex geological environments will prove difficult to analyse.
In channelized systems, such as alluvial and deep sea fans, the reservoir geometry may be poorly represented by simplistic geometrical arrangements that exist in the current analytical models. For example, the calculation of the distance to the no-flow boundaries is disturbed by the presence of levees. This aspect of the problem is clearly important as such calculations lead to an estimation of channel width, which may later be used as an input parameter for stochastic modelling.
Results of flow simulations of well tests from such complex geometries are presented in this paper. Using finely-gridded models generated from outcrop description and stochastic modelling, the influence of different geological parameters on pressure response is evaluated.
The study is performed in four steps. Firstly, a field example is used to define the problem: a pressure transient test is interpreted in terms of complex geology by the use of a combination of analytical solutions. Secondly, a known reservoir geometry (from outcrop study) is input into a well-test flow simulation model. Thirdly, a more complex reservoir is generated by stochastic (Boolean) techniques which is also simulated as in step 2. Fourthly, a new analytical solution allows for the correct interpretation of the original field example.
When reservoirs are characterized by channel type features, and particularly stacked channels, the no-flow boundaries identified on the derivative curve represent the limits of the system, rather than the limits of individual features. When channels are connected by levees, the levees influence the calculation of the distance to no-flow boundaries. The presence of levees increases the apparent channel width. All well-test interpretation results must be checked by comparison with the best available geological description of the sedimentary environment before quantitative data are supplied for geostatistical modelling.
Stress Sensitivity of Low-Permeability Sandstones From the Rotliegendes Sandstone
Authors: Farquhar R. A. , Smart B. G. D. , Todd A. C. , Tompkins D. E. , Tweedie A. J. 
Published: December 2007

ABSTRACT
Rotliegendes sandstones have been found to display a wide range of petrophysical and mechanical properties stress sensitivity behaviour. The extent of stress related changes has been found for permeability, electrical conductivity and Young’s modulus to be related by the depositional facies. It has also been noted that the relationship between some rock properties which are thought to exist in situ can not be replicated unless measurements conducted at near in situ stress levels are employed. These results lead to the conclusion that the structure reflected by properties measured at low confining pressures is not representative of that which exists in situ.
On Perforating and Fracturing of Deviated Cased Wellbores
Authors: Yew C. H. , Mear M. E. , Chang C. C. , Zhang X. C. 
Published: December 2007

Abstract
The growth and link-up of mini-crack initiated at perforated holes from a deviated cased wellbore were studied by analyzing the behavior of cracks in the tangent plane of the borehole. Muskhelishvili's complex potential functions were used to construct the Green's function, which related the fracture opening displacements and external loads, for computational analysis of the problem.
It was demonstrated that, at a small perforation spacing, the mini-cracks from the perforated holes will link-up forming a large fracture along the wellbore. For cased wellbores, however, the fracture opening surface is not a smooth surface and there are large amount of rock masses entrapped by the connecting cracks. A rough fracture opening area and the entrapped rock masses might be the reason for the reported high friction loss in several deviated cased wells. It was also demonstrated that the situation could be greatly improved when the wellbore was fractured at a pressure which is much higher than the breakdown pressure.
Description of a Large, High-Pressure Slot Flow Apparatus for Characterizing Fracturing Fluids
Authors: Rein R. G. , Lord D. L. , Shah S. N. 
Published: December 2007

Abstract
A large slot flow apparatus for investigating hydraulic-fracturing fluid flow and proppant transport phenomena has been installed at the University of Oklahoma. The apparatus weighs 38 tons, has an adjustable width flow channel that is 9.3 ft long by 7 ft high, and includes capabilities for investigating leakoff phenomena and observing proppant transport. Operating conditions are pressures to 1200 psi and temperatures to 250°F. Initial tests, with a Newtonian fluid and with a 60 lb/Mgal hydrox-ypropyl guar (HPG) solution, show that all aspects of the apparatus and associated instrumentation needed to characterize the flow behavior of these fluids are working satisfactorily.
Field Application and Results of Pipe Tripping Nomographs
Authors: Bazer Donald A. , Owens Harry B. 
Published: December 2007

Abstract
Operational problems associated with tripping drill pipe or running casing become more severe and complicated as drilled holes get deeper and smaller. To reduce the many calculations required, primarily by the men on the rigs, nomographs were developed for solving annular, hole and pipe capacities and displacement volumes. A set of simplified nomographs were also developed, from previously published formulas, which can be used to estimate swab or surge pressures generated when annulus displacement mud flow is laminar. Examples of the use and accuracy of the nomographs are presented. The field results of using these presented. The field results of using these nomographs are mostly in the form of trouble free pipe trips, but some interesting and informative pipe trips, but some interesting and informative field results are presented.
Introduction
The swab and surge pressures generated while tripping pipe, become more critical as wells are drilled deeper and holes get smaller. If abnormal formation pore pressures are encountered which approach the formation fracture pressures, the problem becomes even more pressures, the problem becomes even more critical.
Induced swab or surge pressures while tripping out or into a hole cannot be eliminated but can be reduced to safe values. The most critical conditions exist when the mud hydrostatic pressure is very close to either the formation pore or fracture pressure.
Several methods for predicting swab and surge pressures while tripping pipe have been published. The mathematical methods, published. The mathematical methods, which have been proven to the most accurate by actual test, were found to be too involved and laborious for use by field personnel. The graphical methods found in the literature did not cover all ranges of mud properties and pipe-hole size combinations, and therefore pipe-hole size combinations, and therefore were deemed inadequate for field use. Using the proven mathematical methods developed by J. A. Burkhardt, nomographs were developed and are included in this paper. The nomographs have been in use for approximately one and one-half years and have proven to be reliable. Also included are nomographs for displacement volumes of drill pipe and collars, and annular or hole capacities developed as additional aids for the man on the rig to use in conjunction with tripping pipe.