bluuebunny/crossref_metadata_2025_split huggingface dataset:
Transient Rate Behavior of Finite-Conductivity Asymmetrically Fractured Wells Producing at Constant Pressure
Authors: Resurreicão C. E. S. , Fernando R. 
Published: December 2007

Abstract
The transient rate behavior of finite-conductivity asymmetrically fractured wells producing at constant pressure is presented in this work. A new semi-analytical solution is obtained by means of the Green’s functions method. Two sets of type curves are developed: log-log curves of l/qwD versus tDxf, intended for rate performance forecasting, and log-log curves of (1/qwD)/(2∂(1/qwD)∂ln tDxf) versus CfD2tDxf, for use in fracture characterization. The various transient flow periods are documented.
Asymmetry is measured by the parameter a, which varies from zero, in the symmetric case, to one, in the case of a well located at the tip of the fracture. Analysis of results indicate that the occurrence and duration of the bilinear flow period is greatly influenced by the asymmetry of the fracture. It is also found that the late time transient rate behavior of the well is not practically affected by asymmetry when a ≤ 0.4, in the whole range of fracture conductivities examined, 0.1 ≤ CfD ≤ ∞. No effects are either evidenced when CfD is larger than approximately 30. Correlations to calculate pseudo-skin factors caused by fracture asymmetry are provided.
An example of application is included to illustrate the use of the type curves for fracture characterization and for production forecasting of the well.
Nonisothermal Unsteady Gas Flow in a Coupled Reservoir-Wellbore System
Authors: Dias S. G. , Bannwart A. C. , Serra K. V. 
Published: December 2007

ABSTRACT
The objective of this work is to investigate the behavior of a coupled wellbore-gas-reservoir system. Initially, the system is at static conditions and may flow at constant surface rate. Non-isothermal flow is considered in the reservoir and in the tubing string. The partial differential equations and auxiliary conditions which govern the flow in the reservoir are coupled with the wellbore equations - modified by the method of characteristics - using a finite difference scheme. Results of pressure and temperature versus time can be displayed in many different positions. Particularly, the downhole wellbore flowing pressure, usually used in well test analysis, is investigated in depth. A damaged region around the well is considered. Comparison with isothermal systems showed that for long-time flow regimes the conventional semilog analysis is of good accuracy. However, for short-time analysis influenced by wellbore storage significant errors may occur which depend upon the flow parameters and thermal properties of the system.
Modeling Reservoir Heterogeneity in a Fluvial Sandstone: The Gypsy Sandstone of Oklahoma
Authors: O’Meara D. J. , Haynes B. , Doyle J. D. , Sweet M. L. , Langlais V. 
Published: December 2007

Abstract
Reservoir simulation models based on detailed outcrop description provide a means to evaluate the importance of various types of heterogeneity on reservoir performance. This study models tracer flow in a multistoried fluvial sequence, the Pennsylvanian Gypsy sandstone. To better understand the effects of heterogeneity on a subsurface fluvial reservoir, three-dimensional reservoir simulation models were constructed incorporating information from correlative rocks which outcrop fifteen miles from the subsurface site. The heterogeneity considered in this study is the higher-order architecture of the Gypsy i.e. its channel sandbody configuration.
At the five acre subsurface site, six wells penetrate the Gypsy from 890 ft to 1000 ft measured depth and encounter a depositionally similar fluvial sequence as at outcrop. The wells comprise an inverted five spot with one observation well. Within this site, Gypsy net sandstone varies from 27 ft to 60 ft. Cores indicate that the number of channel sandbodies varies from three to as many as six. Gypsy channel sandbodies can be subdivided into three intervals primarily on correlation of laterally continuous mudstone and siltstone bodies. Within these intervals, correlation of individual channel sandbodies is uncertain.
Due to uncertainty in channel sandbody distribution, the general approach is to develop multiple reservoir models. Each of these models honors well data but differ in configuration of channel sandbody orientation. However, for each, interpretation of channel sandbody configuration is constrained by information on channel patterns from the outcrop and by local net sandstone trends surrounding the subsurface site.
Scale of Heterogeneity and Fluid Flow Response in Carbonate Ramp Reservoirs: San Andres Outcrop, Algerita Escarpment, New Mexico
Authors: Lucia F. J. , Senger R. K. , Fogg G. E. , Kerans C. , Kasap E. 
Published: December 2007

ABSTRACT
Regional to interwell scales of heterogeneity are exposed in the San Andres outcrops along the Algerita Escarpment in the Guadalupe Mountains of New Mexico. The regional strati-graphic framework is composed of five sequences: a lower to middle San Andres sequence and four upper San Andres sequences. Each sequence is composed of systems tracts that contain a number of parasequences. Stacking patterns of parasequences and of fades and rock-fabric successions within parasequences are systematic and provide the necessary geologic framework for petrophysical quantification of geologic models.
Detailed geologic mapping at the interwell scale in a 2,500-ft-long and 160-ft-high outcrop of the basal upper San Andres sequence in a ramp-crest facies tract shows a geologic model composed of nine shoaling-upward parasequences 10 to 40 ft thick. The parasequences are composed of vertical and lateral successions of dolomitized mud-dominated to gram-dominated rock fabrics. Low permeability mudstones and wackestones, typically found at the base of parasequences, display variable degrees of lateral continuity. High permeability is restricted to grain-dominated packstones and grainstones containing inter-granular porosity that are typically found at the top of parasequences, although mud-dominated packstones and wackestone may also occur at the top of parasequences. Some parasequences are capped by tidal-flat facies which are considered to be tight by analogy with subsurface tidal flat facies. The grainstones of parasequence 7 are unique having high volumes of moldic (separate-vug) porosity and anomalously low permeability values.
Pressure Buildup Testing as an Aid in Well Stimulation: Case History
Authors: Robinson J. C. , Chu W-C. , Woods M. E. , Hutchison H. W. 
Published: December 2007

ABSTRACT
Pressure transient testing and stimulation treatment programs are presented for four development/exploratory wells located in the Sand Dunes Field in Wyoming’s Powder River Basin. While pressure buildup tests conducted during initial completion yielded relatively high permeabilities and severe skin for all but the initial well, core analyses yielded much lower permeabilities and suggested low susceptibility to damage. The core data were discounted, and the buildup test data were relied upon to design small hydraulic fracture treatments to overcome suspected near-wellbore damage. As a result of the treatments, significant increases in productivity occurred which verified the buildup interpretation.
For all four wells, stimulation treatment data and pre-and post-stimulation buildup test analyses are presented. Application of the pressure derivative analysis technique is demonstrated. Through comparison of pressure responses in damaged and improved systems, qualitative as well as conventional quantitative transient test analysis techniques are presented.
The utility of pressure buildup testing for identifying stimulation candidates and providing reliable fracture design data is illustrated. Relying on core data in this field would have resulted in inappropriately designed, less cost-effective hydraulic fracture treatments, and serious underestimation of production potential. The effectiveness of small hydraulic fracturing treatments designed solely to penetrate extremely high skin is demonstrated.
The Value of Reservoir Test Systems (Exploratory Phase) in High-Cost Offshore Areas
Authors: Allison M. F. 
Published: December 2007

Abstract
Offshore projects can be very expensive and risky, especially in deep waters now being explored. This analysis was performed to determine the benefits which would be realized from extended reservoir testing of offshore prospects in the Gulf of Mexico prior to committing to full field development. The analysis investigates whether extended testing is beneficial where development costs are high (over ± $250MM) and possibly very risky.
When large reserves are discovered, will the expense of extended testing be justified? To determine this, test objectives are established. The expected production rates, reservoir size, and facilities needs are considered. Then a risk analysis of four specific test systems is performed to determine how valuable each would be in terms of reducing economic risk. These test systems alone can be very expensive, so the cost of each system must be justified by quantifying its value using risk analysis. Two examples are used to conclude that unless development costs are extremely high, elaborate and costly test systems cannot be justified a majority of the time, but the appropriate test system should be used in proportion to the investment.
This evaluation was first proposed to determine specific design criteria and objectives of extended tests in deep water prospects. Four specific test systems were considered:
A Better Environmental Management System
Authors: Jennett L. E. 
Published: December 2007

Abstract
This presentation will address how to organize and strengthen a company-wide environmental program, how to market the issue internally and how to define and implement accountability in the field. Long range planning for environmental management for the next decade will be discussed. The data for the recommendations was obtained from experience in developing a management program for oilfield service operations as well as interviews with different companies on the success and failures of corporate programs.
A New Technique for Servicing Horizontal Wells
Authors: Tailby R. J. , Yonker J. H. , Pearce J. L. 
Published: December 2007

ABSTRACT
The drilling of horizontal wells is accepted and well-known technology. Many of them have been completed specifically as horizontal wells, but few have been subsequently serviced to their full advantage. This paper presents a completion method and maintenance technique that allows the operator control of individual zones in a long horizontal well. The technique has been prototype tested and shown to be feasible for most basic well operations.
Thru-Tubing Inflatable Workover Systems
Authors: Coronado M. P. , Mody R. K. , Craig G. C. 
Published: December 2007

ABSTRACT
Recent technological advances in inflatable packing element design has allowed non-conventional workover techniques to be accomplished through the production tubing. The improved capabilities of these elements, coupled with new tool designs allowing workovers to be completed with coiled tubing or electric wireline, has seen growing applications. These workovers include, selective and zonal chemical treatments, temporary and permanent plugback operations, intermediate zone blankoff, production and injection flow profile modifications and formation fracturing. They are completed without pulling the production tubing from the well, and thus do not require a rig on the well. Since these tools are snubbed in the well with coiled tubing or electric wireline, thus eliminating the need to kill the well, heavy weight kill fluids, which may cause formation damage, are not required. These tools have been designed to operate with hydraulic pressure and workstring tension within the coiled tubing limitations.
The advancement of this technology has led to a major cost saving alternative to conventional rig workover techniques. The recent improvements made in this equipment has substantially improved the capabilities and reliability of these methods. Major operating companies, utilizing these methods, have realized substantial cost savings in their workover programs.
This equipment has been designed to run through major sizes of production tubing and set in the larger production casing below. The inflatable elements have the capability of being set in casing diameters over three times their run-in diameter. The tools may also be utilized in wells with much higher temperatures than previous technology allowed.
This paper outlines the development of these Thru-Tubing systems and application techniques that have been developed as a result of their field use. It discusses case histories of applications using this technology and the resulting increase in well performance. This paper also describes auxiliary equipment that has been developed to allow these tool systems to be used safely on coiled tubing and electric wireline.
The Effect of Temperature on Minifrac Pressure Decline
Authors: Zhu Ding , Hill A. D. 
Published: December 2007

ABSTRACT
This paper will present a mathematical and numerical model to simulate temperature and pressure behavior and their interference including the effect of fracturing fluid compressibility during a minifrac pressure test. The numerical solution and the approximate analytical solution of the Perkins-Kern-Nordgren1,2 (PKN) model were employed to calculate the fracture geometry, namely fracture length, L, and width, w, before shut-in. After shut-in, linear elastic theory was used to calculate the fracture width from simulated pressure.
The results of the model indicate that the fracture temperature changes significantly during a minifrac test, and the pressure is higher and declines at a slower rate for a compressible fluid compared with an incompressible fluid. The fluid loss coefficient estimated from the pressure decline by the standard analysis will be low if the fluid is compressible. This effect tends to be more severe if the fluid is confined (i.e., the fluid loss coefficient is low). In extreme cases of a highly compressible fluid and a low fluid loss coefficient, the model predicts that pressure can actually increase after shut-in. Most importantly, it is observed from this work that the error in estimating the fluid loss coefficient, using the standard analysis, decreases when shut-in time increases. Therefore, the error in estimating the fluid loss coefficient can be minimized by using pressure data from later in the shut-in period.
Modelling Steam-Assisted Gravity Drainage Process in the UTF Pilot Project
Authors: Siu A. L. , Nghiem L. X. , Gittins S. D. , Nzekwu B. I. , Redford D. A. 
Published: December 2007

ABSTRACT
The Underground Test Facility is designed to test the application of the steam-assisted gravity drainage process for the in situ recovery of bitumen, using horizontal wells drilled from tunnels below the pay zone.
This paper presents a history match of the early injection and production data from the first well pair drilled in the pilot project. The field data showed high oil recoveries and large well head differentials between the injection pressure and the production pressure. The wells were 150 m long, with 93 m inclined and 57 m horizontal.
The history match was performed with a coupled reservoir / wellbore simulator. The wellbore equations take into account frictional and hydrostatic pressure drops, as well as the heat transfer between tubing flow and annulus flow
Simulation results indicated that most of the pressure drop occurred in the injection tubing. The substantial pressure drop (650 kPa) even in this short well implies that frictional pressure drop calculations should be included in designing longer wells for commercial projects.
The presence of shale streaks between the wells delayed the development of the steam chamber locally, and reduced the simulated bitumen production rates.
Engineering Training -- The University Viewpoint
Authors: Miller Frank G. 
Published: December 2007

1961 California Regional Meeting, Bakersfield, Nov. 2–3, 1961
We have one overriding problem in petroleum engineering education today. That problem is how to attract sufficient freshman students of high caliber.
There are some apparent reasons for this, and some potential solutions which I should like to propose. That there are many other ways to get at the problem I have no doubt; it is my primary purpose here to delineate the problem and, hopefully, to stir some interest in solving it.
First, let me point out that there seems to be reasonable agreement among industry, government, and the educational world on just what sort of graduates ought to be coming out of our petroleum engineering curricula. That we need leadership in our newcomers is plain; we also agree that this leadership must come from a combination of talents, primarily two: sound technical training, foundational for as far as the individual cans advance in petroleum engineering, and breadth of view, so that the individual does not become bogged down in a narrow specialization, losing his view of the horizons of this vital field of endeavor.
As far as technical training is concerned, we are sorely pressed. Petroleum engineering has mushroomed in the past decade. One man can not be well informed on all phases of the subject, all techniques. Indeed, it is a monumental task to keep abreast of the vast outpourings of literature in even one phase.
Reservoir Gas Management in the Brae Area of the North Sea
Authors: Phillips I. C. 
Published: December 2007

ABSTRACT AND SUMMARY
This paper traces the development of a group of North Sea oil and gas condensate fields, known as the Brae Area, highlighting the considerable gas management challenges.
South Brae, a black oil field, was first on production in 1983. Approximately 40 Bcf (1.1 × 109 m3) of associated sour gas had to be temporarily stored in the reservoir, creating reservoir management complications as the gas cap has fingered downdip to producing wells, and calcium carbonate scale formation has been exacerbated.
Early in 1988 came North Brae, a gas condensate field developed by gas cycling. Along with residual North Brae gas, the gas temporarily stored in South Brae is injected into the reservoir, to enhance pressure maintenance. The liquid recovery benefits of this development technique are examined.
In 1989, Central Brae, a small oil field similar to South Brae, was developed as a subsea satellite to South Brae. Its gas is also used to enhance North Brae liquid recovery.
The recently approved East Brae field is another giant gas condensate reservoir, due onstream in 1993. This field will also be developed by gas cycling, using some
North Brae gas to enhance pressure maintenance. The paper examines the inter-relationship between gas sales, availability of gas for injection into East Brae (from Brae and other fields) and the degree of pressure maintenance (and hence liquid recovery) anticipated for East Brae.
A Practical Approach to Original Gas-In-Place Estimation: Development of the South Wilburton Field
Authors: Guardia M. A. , Hackney R. M. 
Published: December 2007

ABSTRACT
Based on actual field data from the South Wilburton field in eastern Oklahoma, this paper presents an approach to original gas in place (OGIP) estimation in gas fields during early development. This approach integrates material balance and Fetkovich decline curve analysis, both classical techniques. These classical techniques are enhanced with modern digital tools such as digital recorders and microcomputers, which in many cases eliminate the requirement for lengthy shut-ins and extensive manipulation and filtering of data. Thus, OGIP estimates can be arrived at quickly and in a practical manner during the development of a new field with confidence stemming from convergence of the two techniques. This allows the working interest owner to reassess and modify developmental strategies and play participation. The approach has been utilized in the development of the South Wilburton field and has assisted developmental decision making.
North Sea Chalk Reservoirs: An Appealing Target for Horizontal Wells?
Authors: Selvig A. , Kossack C. A. 
Published: December 2007

ABSTRACT
North Sea chalk reservoirs are characterized by thick formations, low kv/kh-ratios and a low to medium degree of fracturing. Primary recoveries are generally low, in the range of 15-20%. Utilization of horizontal wells could be an efficient tool to increase production rates and improve recoveries from these fields.
A comparative dual porosity reservoir simulation study of horizontal and vertical wells in a North Sea naturally fractured chalk reservoir has been performed. The numerical results are compared to single phase, analytical solutions to investigate the validity of the latter approach. A future strategy for the application of horizontal wells in these fields is also discussed.
The study shows that analytical approaches are valid only for initial screening purposes. To ensure an improved productivity, horizontal wellbore sections should be drilled as long as possible (&gt; 600 m) to maximize the benefit of the steeply dipping natural fracture pattern present in the fields. Numerical results are presented which identify the sensitivity of the horizontal well performance to key properties of the chalks and to different horizontal well trajectories. The study verifies that horizontal water injectors may enable injection into the low-productivity flank intervals of the chalk reservoirs. In a waterflooding environment, the study shows that horizontal wells can be utilized to minimize water production and thereby sustain the future production from the chalk fields.
Site Selection, Well Planning, and Collision-Avoidance Considerations for the Piper Field Redevelopment
Authors: Taylor D. P. , Johnstone J. A. 
Published: December 2007

Abstract
This paper focuses on the unique problems that were confronted in the process of formulating and implementing a field redevelopment strategy for the Piper field, located in Block 15/17 of the UK North Sea continental shelf. The original Piper A development, including 56 directionally-drilled wells, was lost on 6 July 1988.
The process of selecting a site for the Piper B drilling template is reviewed in the context of:
the proximity of oil and gas pipeline networks serving the Tartan and Claymore platforms; the proximity to subsea wells and debris at the Piper A site; the presence of shallow gas hazards in areas adjacent to the Piper A site; the requirement for directing some replacement wells to the original Piper A targets; the requirement for directing other replacement wells to revised targets.
The drilling of Piper B redevelopment wells in close proximity to the Piper A well cluster requires an unusually rigorous and comprehensive approach to collision avoidance, as the possibility for deep intersection with existing wellbores poses a substantial drilling hazard. Key considerations in the planning and execution of Piper B directional drilling include:
the QC of survey records for the original Piper A wells; the quantification of survey errors in the original Piper A surveys; the assignment of error models for the calculation of positional uncertainty; the generation and maintenance of clearance reports.
To date, six directional wells and two sidetracks have been safely drilled through the Piper B template. Strategic site selection and the highest standards of directional well planning and collision avoidance surveillance have been key ingredients of the ongoing and successful redevelopment of the Piper field.