bluuebunny/crossref_metadata_2025_split huggingface dataset:
Auk Field Development: A Case History Illustrating the Need for a Flexible Plan
Authors: Ray Buchanan , Hoogteyling Laurens 
Published: December 2007

The Auk field produces from thin, but highly permeable, Zechstein dolomites. The reserves of the field were defined poorly after the initial four wells were drilled, primarily because of the lack of seismic control. This paper contrasts the initial development plan with the historical sequence and shows how unexpected reservoir response was monitored and interpreted and how it influenced development drilling.

Introduction
The Auk field, discovered in 1971, is not typical of the North Sea. This small carbonate oil reservoir already has reached an advanced stage of development. All except one of the 10 slots on the drilling/production platform have been drilled - some deviated at angles up to 65°. The cumulative production is already more than one-half the estimated ultimate recovery.
The field is unusual in that the very thin Zechstein carbonate producing horizon could not be mapped directly by seismic data, so that both the structural attitude and areal spread of the accumulation initially were defined very poorly.
Potential difficulties during development of the Auk field were apparent at an early stage, and we realized that a flexible approach would be needed. A small integrated team of specialists was responsible for planning the development strategy. This team included a seismologist, geologist, reservoir engineer, production engineer, and an economist. Planning decisions thus have benefited from multidisciplinary analysis, and conclusions and recommendations were those of the whole team. This approach proved both necessary and effective.
The main aim of this study is to illustrate how the continuous flow of information necessitated radical revisions of our initial concepts of the Auk field and how development plans were modified continually. Because of space limitations, it is impossible to detail how the views of the various disciplines interacted when formulating each proposal. However, the overriding factors are pointed out, and the reasoning behind changes of policy are indicated.

Discovery and Appraisal
Shell/Esso's Field A in the U.K. North Sea (Auk) was discovered when Well 30/16-1, drilled in about 280 ft (85 m) of water, encountered oil-bearing, thin, vugular Zechstein dolomites unconformably overlain by Cretaceous chalk.1 The well tested 5,900 B/D (938 m3/d) of 37°API (0.84 g/cm3) oil with an extremely high productivity index. The underlying Rotliegend formation, which had formed the main objective of the well on the pronounced Auk horst structure, was found to be water-bearing.
Because the thin Zechstein formation could not be distinguished on seismic sections, the extent of the accumulation was in doubt. The high productivity of the Zechstein formation also could have been a local phenomenon because tight Zechstein was present in nearby exploration wells.
Analytical Modeling of Oil Recovery by Steam Injection: Part 2 – Asymptotic and Approximate Solutions
Authors: Yortsos Y. C. , Gavalas G. R. 
Published: December 2007

Abstract
This article studies the development of asymptotic and approximate solutions for the growth of the steam zone in steam injection processes in one-dimensional reservoirs at constant injection rates. These solutions generally are derived by using integral balances which include heat losses to the surroundings and the hot liquid zone. In this way, the effects of preheating caused by heat transport in the hot liquid zone ahead of the steam front are accounted for completely.
At the beginning of injection, the advance of the front is well described by the Marx-Langenheim (ML) model, provided that the injection rates are sufficiently high. At longer times, deviations occur and a criterion is developed in terms of a single heat transfer dimensionless parameter, R, that defines the time interval of applicability of the ML model. The asymptotic behavior at large times depends solely on a dimensionless parameter, F, defined as the ratio of the latent to the total heat injected. It is shown that the final dimensionless expression does not depend on R (i.e., on the injection rates) although the time taken to reach the asymptotic state is influenced significantly by R.
An approximate analytical solution that reduces to the respective asymptotic expressions at small and large times is obtained under conditions of high injection rates (R ≫ 1). The solution is shown to give a better approximation to the steam-zone growth rate for intermediate and large times than the approximate expressions developed by Marx and Langenheim,1 Mandl and Volek (MV),2 and Myhill and Stegemeier (MS).3 For a wider range of operating conditions, including low injection rates (i.e., for R between 1 and ∞), an approximate numerical solution based on a quasisteady state approximation is presented. The proposed solution requiring very modest computation is expected to give reliable results under a variety of operating conditions.
Oil/Water Separation in Liquid/Liquid Hydrocyclones (LLHC): Part 1—Experimental Investigation
Authors: Gomez Carlos , Caldentey Juan , Wang Shoubo , Gomez Luis , Mohan Ram , Shoham Ovadia 
Published: December 2007

Summary
An extensive experimental program has been conducted using a 2-in. hydrocyclone. The inlet flow conditions are: total flow rates between 18 to 27 GPM, oil-cut up to 10%, median droplet size distributions from 30 to 180 μm, and inlet pressures between 60 and 90 psia. The acquired data include the flow rate, oil-cut, and droplet size distribution in the inlet and in the underflow; the reject flow rate and oil concentration in the overflow; and the separation efficiency. Additional data were taken from the literature, especially from the Colman and Thew1 study. This experimental investigation provided insight into the hydrodynamic flow behavior in the liquid/liquid hydrocyclone (LLHC), and helped develop and refine a mechanistic model for the LLHC, which is presented in Part 2 of this paper.
Assessment of Salt Loading on Well Casings
Authors: Willson S. M. , Fossum A. F. , Fredrich J. T. 
Published: December 2007

Summary
Assuring the integrity of subsalt wells in the deepwater of the Gulf of Mexico throughout the field's life is a major drilling engineering challenge. The consequences of well failures may result in billions of dollars in remedial costs and lost production. On the other hand, the costs associated with overly conservative well design are significant, which motivates systematic analysis of casing loading for scenarios of interest.
Simplified hole-closure and casing-design guidelines for salt, many developed for the western U.S. Overthrust Belt, are not appropriate for the relatively pure, slow-moving halite found along the Gulf Coast. Instead, our work applies knowledge gained by Sandia Natl. Laboratories from technical research and development (R&D) investigations of the Waste Isolation Pilot Plant (WIPP) and the Strategic Petroleum Reserve (SPR) to determine the magnitude and timing of salt loading on well casings in the Gulf of Mexico.
If hole quality can be assured, the analyses presented show that it is not always necessary to cement the casing/borehole annulus through the salt because the subsequent uniform loading is insufficient to substantially deform the casing. This poses no threat to drilling operations or impingement on the inner casing string in the long term and results in considerable cost savings. However, if hole quality is poor, a cemented annulus is necessary, as the cement effectively transforms the potentially nonuniform loading situation into one of uniform loading.
Significant benefits can accrue from quantifying the magnitude and timing of salt loading. Difficult cementing jobs and liner tiebacks can be omitted and a more aggressive well design adopted. The simplified well design, and the elimination of potentially troublesome operations, leads to millions of dollars in cost savings in individual wells.
New Horizons for Gas in Europe
Authors: Symonds Edward 
Published: December 2007

Abstract
Since 1956, when extensive gas reserves were discovered in Africa and Libya, and the discovery of the Groningen field in The Netherlands in 1960, the picture for a strong gas industry in Europe has been growing more distinct. Advances in gas transportation and storage are contributing to the prospect for gas usage in Europe. Although the present usage is low, the possibilities for favorable costs in relation to competing energy sources and the potential demand show the market is there. In addition to domestic usage, industrial markets can be developed for the future. Political as well as economic forces are discussed in relation to developing the gas markets in Europe.

Introduction
For some years, natural gas was the neglected child of the petroleum business. The position in the United States, where it accounts for nearly one-third of the primary energy used, was regarded as exceptional if not unfortunate, and there was a tendency to overlook the few other areas where it has reached a high state of development. Today, the enormous and rapidly growing hunger for energy outside North America suggests that gas will take its place alongside oil, and of comparable importance, in other major markets. In this transition, the lead is likely to be taken by Europe. This remained a somewhat remote possibility so long as the gas had to be brought nearly 3,000 miles from the large Middle Eastern reservesfor which substantial markets have still to be developed. Following the first Saharan finds in 1956, discovery that North Africa possessed both those reserves, now estimated at 55 Tcf, and extensive others in Libya, promised to change this picture. In 1960, the accessibility of gas to European consumers was still further increased by the discovery in The Netherlands of what has since proved to be the second largest field in the world. The Groningen reserves, now estimated at almost 39 Tcf, put The Netherlands ahead of Canadaalready a major gas-producing country with an area more than 250 times as large.

Progress in Gas Transportation
The prospect for gas usage in Europe is being further improved by advances in transportation and storage. Experience in North America has amply demonstrated the capacity of pipelines to transmit gas to remote consuming markets at highly competitive prices. With a cost of transportation from Texas to the New York area approximately 25cts/Mcf, or from the Alberta fields to San Francisco of 20cts/ Mcf, the low energy/volume ratio (and therefore low flexibility) of natural gas in relation to oil has been largely overcome in this Continent. But transportation costs here were not directly comparable with those in Western Europe so long as Middle Eastern or North African gas reserves were the only ones in sight. It has been estimated that the cost of a normal water-crossing is about twice that for a comparable pipeline laid on land.
JPT
P. 499ˆ
Optimization of the Productivity Index and the Fracture Geometry of a Stimulated Well With Fracture Face and Choke Skins
Authors: Romero Diego J. , Valkó Peter P. , Economides Michael J. 
Published: December 2007

Summary
For a given reservoir of known permeability and dimensions, the proppant mass injected to the pay determines a unique proppant number. Unique to each proppant number, there exists an optimum dimensionless fracture conductivity that exclusively determines the optimum fracture dimensions.1
Impairments affecting flow perpendicular to the fracture surface are accounted for as fracture-face-skin effect. On the other hand, flow impairment caused by a reduction of the fracture conductivity near the wellbore is called choked fracture skin. Both effects have a large influence on the productivity of a fractured well.
In this work, the performance of a fractured well is calculated with a direct boundary element method. This method provides the dimensionless productivity index, and the model allows for the presence of each of the two different skin effects.
The fracture face skin was found to have a significant detrimental effect on the dimensionless productivity index, even changing the character of its dependence on the dimensionless fracture conductivity. The effect of the choke skin also was found to be potentially detrimental but less complex to account for because it can be represented as an apparent reduction in the proppant number.
Fulfilling the Promise of Low-Dosage Hydrate Inhibitors: Journey From Academic Curiosity to Successful Field Implementation
Authors: Mehta A. P. , Hebert P. B. , Cadena E. R. , Weatherman J. P. 
Published: December 2007

SummaryLow-dosage hydrate inhibitors (LDHIs) have been actively investigated for more than a decade in both academia and the petroleum industry. The promise of LDHIs has been to provide a viable alternative to thermodynamic inhibitors, such as methanol and glycol. Inevitably, the journey of LDHIs from modest beginnings in the minds and laboratories of researchers to a technically robust, operationally simple, and economically viable alternative to conventional inhibitors has been fraught with challenges. In this paper we discuss some of the drivers leading to the development of LDHIs for application in severe deepwater environments. The different classes of LDHIs are discussed briefly, with an emphasis on the applicability window of each inhibitor type. We also provide a detailed summary of the successful implementation of LDHIs in deep water and summarize key learnings obtained from field deployment. We conclude by demonstrating the role of LDHIs in altering industry perspectives on hydrate control and their impact on the system selection and design of new field developments.
History Match Analysis of the Little Creek CO2 Pilot Test
Authors: Youngren Gary K. , Charlson Gary S. 
Published: December 2007

Production and pressure data from the Little Creek CO2 miscible pilot test are history matched using a miscible flood simulator. Simulated recovery is dominated by gravity segregation of CO2 and crossflow of oil. A new pseudorelative permeability technique, which decouples gravitational and viscous fingering effects, is developed and used in the history match.

Introduction
A limited number of carbon dioxide miscible pilot tests have been completed or have enough history to permit a meaningful evaluation. Noteworthy tertiary examples include the SACROC, Twofreds, and Willard tests in west Texas and the Little Creek test in Mississippi. SACROC, Twofreds, and Little Creek were producing pilots; of these, the Little Creek pilot is best suited for a thorough analysis to identify those factors that influenced tertiary oil recovery. The test was well confined and small, with one injector and three producers.The primary objective of this work was to determine the controlling factors in the Little Creek CO2 flood by history matching pressure and production data with a four-component, miscible flood simulator. Additional objectives were to (1) develop, demonstrate, and employ a pseudorelative permeability technique for simulating three dimensional miscible performance with two-dimensional calculations and (2) project performance for different-size CO2 slugs than that tested at Little Creek.

Field Description and History
The characteristics and history of the Little Creek field are documented elsewhere. A limited discussion of the field is presented here for completeness.The Little Creek field is in the Lower Tuscaloosa trend of southwestern Mississippi. It was discovered in 1958. A peripheral line-drive waterflood was conducted from 1962 to 1970, and CO2 was injected into the pilot area from Feb. 1974 to Feb. 1977. Of the 102 million bbl (16.2 x 10(6) m3) of oil initially in place, 25 million bbl (4.0 x 10(6) m3) were produced by primary depletion and 22 million bbl (3.5 x 10(6) m3) were produced as a result of waterflood operations. More than 120,000 bbl (19 000 m3) were produced in the pilot test.The reservoir's pay zone is the 10,750-ft (3280-m) Lower Tuscaloosa Denkman sand, which is Cretaceous in age. The reservoir is controlled stratigraphically, being limited by rapid sand pinchout on the flanks. The reservoir is said to have "remarkably uniform rock properties ... (with) no correlative high permeability zones." The reservoir responded very well to water injection, reportedly "flooding out uniformly ... going to 100% water within 3 months of flood-front breakthrough and conformance was estimated to be 90%" Table 1 lists average rock and fluid properties.The CO2 miscible pilot test was conducted against a pinchout along the eastern edge of the field. As shown in Fig. 1, the pattern is essentially one-quarter of an inverted nine-spot on 40-acre (16-ha) spacing. The pilot area was confined by five backup water-injection wells whose purpose was to prevent migration of fluids out of the test pattern.
JPT
P. 2042＾
Wellbore Storage Effects in Geothermal Wells
Authors: Miller Constance W. 
Published: December 2007

Abstract
The early-time response in the well testing of a homogeneous reservoir customarily is expected to give a unit slope when the logarithm of pressure is plotted vs. the logarithm of time. It is shown that this response is a special case and that another non-dimensional parameter must be defined to describe the set of curves that could take place for each value of the wellbore storage coefficient CD. In addition, the effect of temperature changes along the bore is shown to increase the time when wellbore storage is important.
Imparting Directional Dependence on Log-Derived Permeability
Authors: Schön J. H. , Georgi D. T. , Fanini O. 
Published: December 2007

Summary
Cost-effective, efficient production of hydrocarbons depends on accurate reserves estimates, reservoir architecture, and hydrocarbon distribution. In addition, a complete reservoir description, including both horizontal and vertical permeability, is critical to efficient development strategy. Hydrocarbon recovery efficiency depends on many factors, but one key parameter is the ratio of vertical to horizontal permeability.
There are numerous ways to estimate permeability. It is now possible to estimate permeability from continuous formation evaluation measurements. However, it remains difficult to determine directional permeability. Nuclear magnetic resonance (NMR) logs are used routinely to estimate permeability, but NMR-derived permeability is based on scalar properties (e.g., ϕ, T2 distributions from NMR, and bulk volume irreducible water) and is inherently a scalar property itself.
Few formation evaluation measurements provide directional information. Dip and image logs provide bed thickness and layer dip information, while the multicomponent induction instrument (3DEX*) and crossed-dipole shear-wave acoustic tools provide direct measurements of macroscopic formation anisotropy.
In this paper, we explore theoretically and with real data the computation of permeability anisotropy. We use laminated sand models as well as macroscopic models based on the resistivity anisotropy measurements to estimate kV:kH ratios. In addition to multicomponent induction data, we explore stand-alone and joint interpretation of NMR property variations to predict the macroscopic reservoir permeability anisotropy.
Unconventional Miscible EOR Experience at Prudhoe Bay: A Project Summary
Authors: McGuire P. L. , Holt B. M. 
Published: December 2007

Summary
This paper describes the conceptual development, reservoir simulation, and field testing of a new miscible enhanced oil recovery (EOR) technique at Prudhoe Bay. Two distinct variations of this technique have been evaluated.
The vertical Miscible Injectant Stimulation Treatment (MIST) process involves completing a production well at the bottom of a thick, continuous, watered-out interval. A large slug of miscible injectant (MI) is injected, followed by a small slug of chase water. The MI sweeps rock not contacted by previous MI injection and drives EOR oil to offset producers.
In the lateral MIST process, a horizontal lateral is drilled along the base of the reservoir from either a production well or an injection well. MI is injected sequentially into several intervals along the lateral to mobilize EOR oil from previously unswept areas. The lateral well is then returned to normal production or injection service.
Simulation data indicated that the vertical MIST process could recover more than 200,000 STB of incremental oil per well at initial rates of up to 1,000 STB/D. Calculations for the lateral MIST process indicated potential recovery of more than 1 million bbl of incremental EOR per lateral.
Field results of the MIST process have been mixed but are encouraging overall. Incremental EOR response from the first MIST lateral well through July 2000 was approximately 1,400,000 STB, resulting in a technical and economic success.
Response from three subsequent MIST lateral injectors varied widely. The first vertical well MIST showed little response, but it did provide valuable insight into the performance of the process at Prudhoe Bay. The subsequent vertical well MIST, which had a much larger volume of injected MI, was very successful and has currently recovered over 1,100,000 STB. Cumulative incremental EOR from the MIST wells through July 2000 was more than 5,000,000 STB, with average incremental oil-production rates of approximately 4,000 STB/D. Based on these successful results, an ongoing program of additional MIST wells is planned.
A Study of Vibratory Screening of Drilling Fluids
Authors: Hoberock L.L. 
Published: December 2007

This work presents results of an experimental and theoretical study ofvibratory screening of bentonite/water drilling fluids containing amedium-fine fracturing sand to simulate granular drilled solids. Satisfactory solids conveyance off the screen can be obtained for flat decks if the vibrator is placed to yield proper phasing between the normal and tangential acceleration components at all points on the vibrating deck.

Introduction
Drilling fluids returning from a well during drilling are passed serially through a number of solid/liquid separation devices to maximize removal of drilledsolids from the fluid before reuse. The vibratingscreen or shale shaker, the first device to process thefluid, removes the largest particles. Othersolids-separation equipment in the surface mud system can operate efficiently only if the shale shaker is performing properly. Consequently, it often is considered the most important solids-control device on a drilling rig. Most, if not all, of the various shaker designs now available have evolved from vibrating screens used in other industries, primarily the mining industry. Because of its obvious importance in such industries, vibratory screening has been the subject of numerous studies and investigations. On the other hand, very little investigative work has been published on vibratory screening of drilling fluids. The essential difference between this type of screening and that in other industries is that most of the material processed by a drilling fluid screen is liquid, rather than solid. For example, a well-maintained drilling fluid could have less than 10% tool solids by volume. Consequently, much of the existingtechnology for vibratory screening of dry solids, or even very wet slurries, does not apply toscreening of drilling fluids. The importance of this problem has been recognized by the IADC, which recently sponsored a conference on vibrating screen separators. Because the screen cloth itself is critical in determining the amount and size of solids removed by a shale shaker, the API has published a recommended practice for designating shale shaker screen cloth. More recently, Cagle and Wilder reported results of an experimental comparison between two commercially available shakers, primarily to evaluate a new design in screening cloth. Beyond this study, however, comprehensive investigations of the problem apparently have not been published.
JPT
P. 1889＾