bluuebunny/crossref_metadata_2025_split huggingface dataset:
Results Of Acid-In-Oil Emulsion Stimulations Of Carbonate Formations
Authors: Bergstrom J.M. , Miller B.D. 
Published: December 2007

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

Abstract
A low rate, low pressure stimulation technique using a new surfactant retarded, acid-in-oil emulsion has been found effective in providing better sustained production increases than previously obtained in stimulations using 15% and 28% hydrochloric acid in wells having high temperature, low permeability, carbonate formations. A permeability, carbonate formations. A fracturing technique also using the emulsion provided significant initial production provided significant initial production increases, but rapid declines occurred in most wells.
The results of 22 treatments using the low rate, low pressure technique and 12 stimulations using the fracturing technique are presented, and are compared to 80 previous treatments using 15% and 28% hydrochloric acid in wells having similar conditions.

Introduction
Commercial oil production was established on the Cedar Creek Anticline in Southeastern Montana (Central Williston Basin) in 1952, and major development drilling proceeded through 1965. Approximately 640 wells were drilled during this period on the narrow structure which extended for over 100 miles as shown on Figure 1. Major productive zones encountered were carbonates in the Silurian, Mission Canyon, Stony Mountain and Red River formations.
The area of interest of this study includes the Pennel, Coral Creek, Little Beaver and Little Beaver East Fields on the southern end of the anticlinal structure. The majority of production in the Pennel Field is from the Red River and Stony Mountain formations while production in the other three fields is production in the other three fields is predominently from the Red River alone. predominently from the Red River alone. With few exceptions, the wells are on 160 acre spacing. Average daily production from the four fields during 1974 was approximately 11,000 barrels of oil per day from 200 producing wells or an average of 55 BOPD per producing wells or an average of 55 BOPD per well. Each field is in a secondary recovery phase with waterfloods installed between 1965 phase with waterfloods installed between 1965 and 1969.

MATRIX TREATMENTS USING CONVENTIONAL ACIDS
During the early 1970's, Shell performed numerous low pressure, low rate stimulations (here defined as matrix stimulations) using 15% and 28% hydrochloric acid in wells throughout these four fields with modest success. Table I is a summary of the results of all matrix stimulations (a total of 80) that were performed during the period 1971 to 1974. performed during the period 1971 to 1974. Although many stimulations were performed before 1971, waterflood response was not generally noted in these fields prior to this time.
Understanding Proppant Flowback
Authors: Parker Mark , Weaver Jim , Van Batenburg Diederik 
Published: December 2007

Abstract
Proppant production from hydraulically fractured wells can cause severe operational problems, increase safety concerns, and dramatically reduce economic returns on well-stimulation investments. Methods that have helped eliminate or minimize proppant flowback include modified completion designs, the use of controlled fracture closure for obtaining early closure on the proppant pack, and the use of materials designed to reduce proppant production. Curable resin-coated proppants, chopped fiberglass, thermoplastic strips, and chemicals that modify the surface of the proppant are all accepted methods for minimizing flowback.
This paper presents the results of both physical and numerical modeling of proppant flowback recorded during the development of a chemical designed for modifying the proppant surface. The goal of this study was to develop an understanding of the mechanisms that control proppant flowback. Laboratory experiments performed in slot models with no closure stress helped establish the interaction of proppant size, proppant distribution, and fluid velocity. Additional studies of the impact of closure stress, fracture width, and fluid rate on proppant flowback were performed with modified API linear conductivity cells.
Data obtained from the physical modeling were used to calibrate a numerical model that predicts proppant flowback. In this model, fluid flow in the proppant pack is described by Darcy's equation for flow through porous media. The resulting velocity distribution allowed local stability to be assessed along the free surface between the proppant pack and the continuous fluid phase. Repeating these steps allowed evaluation of the interface that develops over time.
The Concept of Mud Weight Window Applied to Complex Drilling
Authors: Charlez Ph. A. 
Published: December 2007

Abstract
This paper deals with the concept of Mud Weight Window (MWW). In the first part, the classical case of passive basin is studied. It is shown that both impermeable shales and permeable reservoirs require overbalanced conditions, in the first case for stability reasons in the second to avoid a kick. It is then quickly explained how to determine MWW from logs in tight shales where direct measurements are not possible.
In the second part, some special complex cases are studied: unfissured and fissured formations, depleted fields, Extended Reach Wells, tectonic areas, deep water and HP/HT wells. In each case the specific MWW generates special problems. Several examples are discussed and operational solutions are proposed.
Optimization of NMR Logging Acquisition and Processing
Authors: Chen S. , Georgi D. , Fang S. , Salyer J. , Shorey D. 
Published: December 2007

Abstract
Successful petrophysical interpretation of NMR logs depends greatly on the selection of acquisition parameters and data processing methods. Routine tool calibration, based on a single fluid, guarantees the accuracy of porosity; however, the tool response to individual 72-components in a multiple fluid-component system is not directly assessed. The MRIL® response to multiple fluids was tested in a multi-fluid calibrator. A series of tests were performed in various logging modes, including standard T2, bound water logging, and dual wait time logging sequences. This investigation provides the basis for a more effective utilization of the MRIL tool with more appropriate acquisition parameters and data processing methods for the petrophysical interpretation of reservoir formation and fluid systems that exhibit bimodal T2 distributions.
For a given bimodal T2 distribution, the ability to detect bimodality depends on (1) the relative magnitudes of the two peaks, (2) the echo-train record length L, (3) the number of echoes N, (4) the data processing method including the proper bin range selection, and (5) noise. Based on the investigation, we discussed our recommendations for selecting acquisition sequences, parameters, and data processing methods.
Characterizing Sound Generated by Multiphase Flow
Authors: Wang Jianrong , van der Spek Alex , Georgi Daniel T. , Chace David 
Published: December 2007

Abstract
A new method for analyzing multiphase flow in wells using acoustic noise and capacitance log data is presented. Although using noise log to detect channeling is a well-established science for vertical wells, their interpretation in highly deviated and horizontal wells is difficult. Little attention has been paid to the shape of the spectra and their relationship to the multiphase flow or to their relationship to well deviation. The acoustic spectra can be decomposed into a background contribution, due to multiphase flow, and an extraneous component. Based on theoretical considerations, we explained the slope of the background spectra. The extraneous component is attributed to activities outside the casing or to fluid entries into the well.
There are two steps in interpreting the noise log data. The first step uses time series analysis of capacitance data to determine the flow regime. Then the noise generated by that flow regime can be characterized since each flow regime has a unique acoustic fingerprint (due to its unique turbulence structure). The second step is to identify the extraneous fluid flow signature. Sound generated by fluid channeling and fluid entry is superimposed on the background sound, which is generated by turbulent fluid motion inside the wellbore. Therefore, the deviation from background sound spectra is assumed to be caused by other sources, such as fluid channeling. Field examples indicate that the identification and characterization of background noise makes the acoustic log interpretation a valuable source for determining fluid channeling in multiphase flow horizontal wells.
Aqueous Systems for Paraffin Removal
Authors: Sutton G.D. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
This paper was prepared for the Society of Petroleum Engineers of AIME Symposium on Formation Damage Control, to be held in Houston, Tx., Jan 29–30, 1976. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal, provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
There are a variety of techniques used in the oil field to periodically remove paraffin deposited on downhole tubular goods periodically remove paraffin deposited on downhole tubular goods and in surface flow lines. Some of these removal methods may have certain drawbacks. Hot-oiling, a popular method of removing deposited paraffin, may contribute to formation damage if used repeatedly in low temperature, low pressure wells. This paper describes a water base chemical system which has been found to effectively remove paraffin from metal surfaces. A simple procedure is outlined in the text for testing aqueous paraffin procedure is outlined in the text for testing aqueous paraffin removal systems. A variety of applications for such a chemical system and some field results are also described.

Introduction
Deposition and accumulation of paraffin type deposits in the wellbore and surface flow lines often hamper production of crude oils. Very few fields in petroleum producing areas are completely free of paraffin problems. These paraffin problems may be so severe that the removal of the deposits must be done as often as once a week in order to maintain production. On the other hand, paraffin deposition may be only seasonal. That is, during cold paraffin deposition may be only seasonal. That is, during cold weather paraffin may only plug surface flow lines. These organic deposits can and often do present a constant source of aggravation to many field operators. Unless operators initiate systematic remedial treatments to remove these deposits, crude production gradually decreases, revenue is lost, and the possibility increases that expensive mechanical failures will result.
There are many reasons why paraffin deposits from crude oil. Reistle and many subsequent investigators have described the mechanism of paraffin deposition in great detail.
Drilling The Limit* – A Key To Reduce Well Costs
Authors: Schreuder J. C. , Sharpe P. J. 
Published: December 2007

Abstract
Well expenditure represents a significant part of Brunei Shell Petroleum (BSP) business, accounting for around 50% of capital expenditure. There is a significant value creation opportunity through achieving excellence in Well Delivery.
Drilling The Limit* (DTL) a Shell trademark, is an alternative planning methodology through which incredible time gains can be made, by applying resources and significant team effort with high focus on "soft issues". The concept was developed from extensive cross-Shell and cross-industry benchmarking including "Technical Limit Drilling"[1][2] and is based on extreme in-depth challenge of well design to identify what is theoretically possible. This theoretical limit forms a stretched target, representing a perfect world. The difference between historical performance and theoretical limit represents opportunity.
The DTL methodology was first tested in BSP on an offshore horizontal development campaign. These wells were delivered with a 40% time saving compared to historical performance, resulting in a 12% reduction in Unit Technical Cost. All these wells are producing above expectation.
This success delivered a performance "roller coaster", resulting in significant acceleration of subsequent wells, presenting a number of challenges for BSP. Resources required for DTL were under estimated as the accelerated work program resulted in even less time for detailed planning of follow up wells. A corporate study[3] confirmed what impact full implementation of the methodology would have on the organisation and its projected business results. Recognising its potential, BSP has planned for a wider application of the DTL methodology, the lessons learned to date are helping the company to plan for the impact of success.
Revitalizing The West Lutong Field
Authors: Pauzi N. , Low F. N. , Abas A. , Juwaini A. R. , Maksari H. 
Published: December 2007

Abstract
Reviving production from declining fields has become a major activity for oil and gas companies. This requires a focused multi-disciplinary team to arrive at a proper understanding of the reservoirs, identify for any remaining bypassed oil and the right technical solution. The West Lutong field is the oldest offshore field in the Baram Delta region located some 12-km offshore Sarawak, Malaysia. It has been on production since 1968 barely two years after the field discovery. The field has been under continuous development ever since, producing at 56000 bopd at its peak in 1972. Currently, the field is producing at 8000 bopd and is on a slowly declining trend. The field comprises a series of multiple stacked deltaic to shallow marine sandstone reservoirs that contain both oil and gas. The observed drive mechanisms consist of a combination of gas cap expansion, water drive and solution gas drive. In production time some of the units have been seen to be preferential swept. In June 1997 a multi-disciplinary West Lutong team was formed to identify bypassed oil and propose additional development. This paper focuses on the occurences of the bypassed oil and the remaining potential. This has enabled the formulation of an optimized development proposal to revitalize an aging field.
An Analysis of Finite-Difference and Finite-Element Techniques for Geothermal Reservoir Simulation
Authors: Faust Charles R. , Mercer James W. 
Published: December 2007

A two-dimensional (areal) finite-difference geothermal model is presented, and results are compared with a Galerkin, finite-element model previously developed by the authors. In both previously developed by the authors. In both models, it is assumed that local thermal equilibrium exists and capillary pressure is negligible. The continuity equations for steam and water are reduced to two non-linear, partial differential equations posed in terms of fluid partial differential equations posed in terms of fluid pressure and enthalpy. These equations are pressure and enthalpy. These equations are applicable to both hot-water (single-phase) and vapor-dominated (two-phase) geothermal reservoirs
In both the finite-difference and finite-element models the time derivatives are approximated by finite-difference expressions. For each time step, this yields a system of nonlinear equations. The nonlinear coefficients are treated as constants during each time step and are evaluated using either the values of pressure and enthalpy at the beginning of the time step or values extrapolated to the mid-time level. In the finite-difference model the solution is improved by Newton-Raphson iteration. This technique markedly reduces mass and energy balance errors while permitting larger time steps. The linearized equations in both models are solved by a Gauss-Dolittle procedure for nonsymmetric, banded matrices. Several example problems, based on analytical solutions and published experimental data, are used to evaluate the relative merits of finite-difference and finite element techniques applied to geothermal reservoir simulation. Results suggest that the finite element method is more suitable for hot-water reservoirs due to less numerical diffusion and better approximations of boundary and internal geometries (with fewer node points). For vapor dominated systems, the finite-difference model appears superior because it reduces mass and energy balance errors and exhibits less numerical oscillation.
Numerical Simulation of Mass and Energy Transfer in the Longwall Process of Underground Gasification of Coal
Authors: Sawyer Walter K. , Shuck L.Z. 
Published: December 2007

To mathematically describe the long wall generator process of underground coal gasification the coalbed is considered as solid carbon with a system of vertical micro-fissures along which combustion reactions occur. Mass and energy balances for the solid and gas phases and a mass balance for each hydrocarbon component are derived. Two overall reactions are considered resulting in seven coupled, nonlinear partial differential equations. partial differential equations. The primary mechanisms of heat transfer are conduction in the solid phase and convection in the gas phase. Also, convective transfer-between the two phases along the fissure walls, phases along the fissure walls, expansion of the fissure system and effective Darcy permeability as a function of distance and time, and temperature-dependent reaction rates are considered.
The equations are written in implicit finite-difference form and solved stepwise in one dimension by direct methods with systematic updating of coefficients. Solutions are obtained for the solid and gas temperature, total gas density, and mole fractions of oxygen, carbon dioxide, and carbon monoxide as functions of distance and time. Boundary conditions include input and output pressures, inlet gas and/or solid temperatures, and inlet oxygen concentration.
Typical sets of temperature and gas component concentrations along the generator length are shown. Curves are shown indicating the effect of the dimensions of the seam and the applied pressure gradient on the energy content pressure gradient on the energy content of the output gas. Also the subsurface energy conversion efficiency is discussed.
Identifying Fracture Geometry in the Appalachian Basin
Authors: Jacot R. Henry , Meyer Bruce R. , Myers Roger R. , Paugh Len O. 
Published: December 2007

Abstract
Identification of fracture geometry is necessary for the proper design and execution of a hydraulic fracture treatment. The Appalachian Basin consists of many different producing formations. These formations can vary in depth from 600 ft. to 7700 ft. Because of the low reservoir pressure (many of these formations are also underpressured) and low permeability, most of these formations require a hydraulic fracturing treatment to be economically successful.
Drill-In and Completion Fluid Formulation and Performance For Open Hole Gravel Packing Deviated Water Injection Wells Offshore Nigeria – A Case History
Authors: Seaton Simon 
Published: December 2007

ABSTRACT
This paper is a review of two recent open hole gravel packed, water injection wells drilled from an offshore drilling rig, with particular focus on the loss of fluids and subsequent control of those losses, and makes recommendations for future wells based on the lessons learned. The techniques and fluids used to drill the deviated interval, place the gravel and remove filter cake prior to flowing back lost fluids and testing injectivity are discussed. The causes of loss of returns at various points during completion operations are identified and the remedial actions taken at the rig site are documented. Suggestions for future operations that should eliminate these losses are also outlined.
The drill-in and completion fluids chosen for these operations had to meet several criteria. In particular the bridging particles selected had to be a size range specifically chosen to effectively seal the formation of interest, and quickly form an impermeable filter cake on the surface of the formation, which prevented further invasion by the well bore fluids and subsequent reductions in formation permeability. Once the zone of interest had been drilled, the filter cake had to provide continued fluid loss control during displacements, placement of completion equipment and gravel pumping operations. However, at times potentially damaging losses were experienced. Once the gravel packing operation was complete, it had to be possible to remove the filter cake and bridging particles so that injectivity could be obtained, without plugging or bridging of the gravel pack or completion equipment. The techniques used to control losses also had to meet the same goals of preventing formation damage and avoid plugging of gravel and completion equipment.
The experience gained on these two wells shows that careful planning of fluids formulation, drilling practices and completion techniques are necessary to ensure the required fluid loss control while drilling and completing the well, especially while placing gravel. The filter cake formed can then be removed at the desired time to ensure maximum injectivity.
Reservoir Development Optimisation Utilizing Nuclear Magnetic Resonance Technology
Authors: Ogun Titus K. , Nwosu C. A. , Phillips O. O. , Jebutu Segun 
Published: December 2007

Abstract
From exploration to development, the challenges of cost-effective exploitation of hydrocarbon reservoirs are enormous and diverse. A lack of detailed understanding of the petrophysical building blocks of the reservoir in the early stages of its development usually constitutes a major impediment to achieving an efficient development strategy. In addition, stratigraphic and structural uncertainties exist and are only minimised as more wells are drilled to develop the reservoir. The hydrocarbon fluid types, accumulation, and stratification can also present complex uncertainties in identification and quantification, depending on the depositional environment of the reservoir.
The EE reservoir is structurally a rollover anticline with shallow marine deposits. It was discovered in 1965 and was put on stream in 1970. The reservoir has had 12 drainage completions to date, 7 of which currently flow with a total daily production of 7,100 BOPD. Until 1998, completion and development had been based on conventional data acquired at various time since the reservoir was discovered.
In 1998, a new nuclear magnetic resonance (NMR) logging device was run in the reservoir for the first time. Logs were acquired in well XT, which penetrates the southeastern flank of the reservoir. The results provided an improved definition of fluid flow units in the reservoir. The effective porosity was found to average between 32 and 34% with less than 2% variation across the reservoir. However, the bulk volume irreducible (BVI) showed considerable variation with depth across the reservoir, defining an egg-shaped flow-unit body. Permeability was on the order of 1.0 darcy, while the clay spectrum indicated laminated interbedded shales with clean sandstone layers cutting across the upper section of the reservoir. Core data from a nearby well was integrated with the NMR results, and a good correlation was obtained. Implications of these data on future completions and reservoir drainage strategy are highlighted in the paper.