bluuebunny/crossref_metadata_2025 huggingface dataset:
A Comparative Analysis of the Production Characteristics of Cavity Completions and Hydraulic Fractures in Coalbed Methane Reservoirs
Authors: Goktas B. , Ertekin T.
Published: December 2007

Coalbed methane wells usually require a stimulation technique because their initial flow rates are often quite low. Hydraulic fracturing is the most common type of stimulation technique applied to coalgas reservoirs. Recently, open-hole cavity completions have become an alternative stimulation technique in coalbed methane reservoirs.

In this study, a three-dimensional, two-phase fluid flow model is used to compare production performances of the cavity-completed and hydraulically fractured wells in coalbed methane reservoirs. A static local grid refinement (LGR) technique is embedded into the model to adequately capture the flow behavior around cavity completions and hydraulic fractures without using excessively large number of grid cells.

The model utilizes a residual equation rather than a wellbore equation to determine the flow rates into the cavity and hydraulic fracture. Both cavity completions and hydraulic fractures are approximated as a combination of fine rectangular grid blocks. The constructed fine grid lines are terminated at the coarse and fine grid block interfaces by implementing the LGR technique developed. The generated flow equations for fine and coarse blocks are, then, solved simultaneously.

Flow performances of cavity completions and hydraulic fractures are compared for various coal seam permeabilities. It is demonstrated that permeability damage during fracturing may have significant impact on the flow performance of the hydraulic fracture. Hydraulic fractures without permeability damage associated perform better than cavity completions if permeability contrast in the coal seam is not significant. In strongly anisotropic systems, however, even if there is no formation damage due to fracturing fluid, cavity completions outperform hydraulic fractures.
A Modified p/Z Method for Coal Wells
Authors: Seidle John P.
Published: December 2007

A straight line, easy to use form of the mass balance equation, the "p/Z plot", is frequently used to determine both Original-Gas-In-Place and initial reservoir pressure of conventional gas wells and reservoirs. A coal well p/Z plot bends to the right, similar to that of a conventional gas well subject to water influx. The theoretical foundations to linearize this plot for coal wells were laid in a simulation study by King (ref. 1) with the introduction of his Z* variable and the resulting "p/Z* plot". However, when King's method was applied to actual coal wells, wildly erroneous results were obtained. Investigation of this failure resulted in a modified, more robust method. As did the original method, the modified method presented here allows determination of OGIP, initial reservoir pressure, and drainage area. This paper documents mathematical development of the modified method, application of both the original and modified methods to simulated coal well production data, and, lastly, application of the modified method to the actual production data which initiated this study.
Rock-Mechanical Model of Thin-Bedded Sands and Shales for Improved Fracture Height Prediction, Mesaverde Sandstone, Wyoming
Authors: Pantoja David , Hurley Neil F. , Graves Ramona M. , Mark Pearson C.
Published: December 2007

The purpose of this study is to construct a core- and log-based rock-mechanical model of thin-bedded sands and shales. The study area is North LaBarge field, Wyoming, where rocks of the Cretaceous Mesaverde Formation produce hydrocarbons from low-permeability, thin-bedded (0.5-10 in; 1-25 cm) sands and shales. Hydraulic fracturing is necessary to obtain production from this reservoir.

For roughly 90 ft (27 m) of core, permeabilities and p- and s-wave velocities were measured every 0.5 in (1.2 cm) using probe-type devices. Laboratory results were converted to subsurface conditions using pressurized core plugs, a full-waveform sonic log, and a density log. The resulting rock-mechanical model provides a detailed stress profile which can be used as input into computer models which predict fracture height. Such models generally use bulk-rock properties in which fracture heights are overestimated because the models do not take into account the ability of thin shales to impede fracture propagation.
Development of a Coiled Tubing Diametral Growth Model
Authors: Yang Y. S. , Gao C.
Published: December 2007

Coiled Tubing (CT) is subjected to plastic mechanical deformation as it is cycled on and off the reel and over the gooseneck. Repeated bending causes CT fatigue, and eventually failure. In the presence of an internal pressure, especially higher pressures (greater than 3,000 psi), CT fatigue is accompanied by diametral growth ("ballooning"). CT diametral growth can cause incompatibilities with deployment equipment and continuous use could thus cause severe mechanical damage to the CT. Therefore, an accurate predictive model for CT diametral growth is needed for both safety and reliability in CT operations.

A reliable CT diametral growth model has been developed based on test data and three-dimensional curve fitting. The developed model not only predicts CT diametral growth under various pressure and bending geometry conditions, but also evaluates the effects on CT growth of relatively small changes in tubing OD, wall thickness, material grade, internal pressure, and bending radius. These analyses will help operators detect early CT diametral growth before severe damage occurs, and eliminate or reduce operational factors that contribute to growth.
Shaly Sand Analysis using Density-Neutron Porosities from a Cased-hole Pulsed Neutron System
Authors: Odom Richard C. , Pavlakos Paul , Diocee Satwant S. , Bailey Shawn M. , Zander Dennis M. , Gillespie John J.
Published: December 2007

A density-based porosity derived from the attenuation of gamma rays created by inelastic scattering of fast neutrons has been developed1,2,3 for the Computalog PND-S pulsed neutron system. The utility of this cased-hole, density-based porosity is demonstrated in reservoir analysis of sand-shale sequences in western Canada, Texas gulf coast, and Montana. Applications (in combination with the cased-hole neutron porosity) include providing porosities where hole conditions make open-hole logging unviable, and in old wells where no modern porosity logs exist or the data is of questionable quality. Low porosity can be differentiated from gas-filled porosity with the use of this measurement in cased-hole prospecting.

In shaly sand analyses, the addition of this novel density measurement to the neutron porosity and SIGMA facilitates a more comprehensive description of the reservoir. LRHO, the pulsed neutron density parameter, and RATIO, the near-to-far thermal ratio, are shown as overlays to identify gas zones. The pulsed neutron density porosity IPHI, which is used in the log analysis examples, is generated by specifically characterizing LRHO for a well or field. A prototypical borehole compensated (BHC) algorithm, that generates neutron (AIPN) and density (AIPD) porosities characterized for specific casing sizes and lithologies, is also used in the log analysis examples. The measurement theory of the PN density is reviewed as it pertains to understanding the log examples.

The correlation with open-hole porosities is demonstrated in several of the log examples. Through application to some typical reservoir description and optimization problems, the log examples show the utility of these measurements in cased-hole reservoir analysis.
Unsteady-State Pressure Distribution Created by a Well with an Inclined Fracture
Authors: Cinco-Ley Heber , Ramey Henry J. , Miller Frank G.
Published: December 2007

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

An analytical solution was derived for the unsteady flow of a slightly compressible fluid toward a fractured well with an inclined fracture in an infinite slab reservoir. This solution was evaluated to obtain the dimensionless pressure drop at the fracture. Fully and partially penetrating fractures were considered. partially penetrating fractures were considered. Tables and graphs of dimensionless fracture pressure vs dimensionless time are presented. pressure vs dimensionless time are presented

Introduction

Hydraulic fracturing has been an effective technique to stimulate damaged wells or wells producing from a low-permeability formation. producing from a low-permeability formation. It has been established that the orientation of a hydraulic fracture is perpendicular to the direction of the least principal stress in the formation. The direction of the least principal stress is not always parallel or perpendicular to the plane of the formation. For this reason it is possible that some hydraulically fractured wells have inclined fractures.

Many authors have studied flow behavior in a reservoir produced through vertically and horizontally fractured wells.

At early times in the unsteady-state behavior of a fractured well there exists a linear flow perpendicular to the plane of the fracture. This can be recognized by a one-half slope line on a log-log graph of fracture pressure drop vs time. Following this flow pressure drop vs time. Following this flow period, there is a transition flow period that period, there is a transition flow period that depends on the geometry of the fracture-reservoir system. At long times, there is a pseudo-radial flow period, if the reservoir is pseudo-radial flow period, if the reservoir is considered of finite thickness and infinite radial extent, and the fracture is of finite extent.

No reference to transient pressure behavior for a reservoir producing through a well with an inclined fracture was found in the literature.

The purpose of this work is to present a solution of the unsteady-state pressure distribution created by a well with an inclined fracture produced at a constant rate.
Urban Oil Production and Subsidence Control - A Case History, Beverly Hills (East) Oilfield, California
Authors: Erickson R.C. , Spaulding A.O.
Published: December 2007

In only a limited number of hydrocarbon producing areas of the United States and producing areas of the United States and elsewhere has the production of oil and related fluids from subsurface reservoirs been correlated with surface subsidence and damage to property in the subsiding area as well as damage to wells and producing facilities as a result of compaction within the productive reservoirs. These limited phenomena have been observed and documented most notably in the Wilmington Oil Field in the southerly portion in the City of Los Angeles and portion in the City of Los Angeles and adjoining City of Long Beach.

The City of Los Angeles has permitted urban oil producing operations for the past 20 years in the belief that the risk of past 20 years in the belief that the risk of significant oil field subsidence is negligible and in the knowledge that should slight negative changes in the surface elevations be noted at or near the outset of production, measures can be taken to abate the condition before damage to surface improvements could occur.

The Beverly Hills (East) Oilfield was discovered during December 1964, and it soon became apparent that a major hydrocarbon reserve had been found. Within three years production rates exceeded 30,000 BOPD from production rates exceeded 30,000 BOPD from reservoirs as shallow as 3,600 feet beneath one of the most densely populated portions of the city. Clearly, the situation required assessment of the subsidence prospects.

The Beverly Hills (East) field is located within an east-west trending elongate complexly folded and faulted anticline situated on the northwesterly rim of the Los Angeles Basin at the common boundary between the cities of Beverly Hills and Los Angeles. Productive limits encompass approximately Productive limits encompass approximately 848 acres within which 6,200 individuals are currently receiving royalty payments. Development drilling has been conducted by two operators Standard Oil Company of California and Occidental Petroleum Corporation and by May 1, 1975, 118 wells had been completed of which 26 are water injection wells. As of May 1975, over 61 million barrels of oil and 124 million MCF of gas have been produced. Production during April 1975 averaged Production during April 1975 averaged 11,000 BOPD and 15,000 MCF of gas per day.
Marine Sewage Regulations and Disposal Methods
Authors: Chance Maurice J.
Published: December 2007

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

This paper provides an examination of the problems associated with the management of problems associated with the management of sewage discharges from watercraft and offshore platforms. Areas of emphasis include waste platforms. Areas of emphasis include waste treatment techniques, Federal legislation concerning waste discharges, and the contribution of discharges to the pollution of navigable waters of the United States.

The intent of the paper is to provide shippers, shipowners, and platform operators with the most recent information on marine sewage treatment systems.

Introduction

Environmental pollution has become a major concern. An increasing number of laws, regulations and standards are being proposed and promulgated to curb detrimental discharges into promulgated to curb detrimental discharges into U.S. waters. Although there are variations in the degree of control by the laws of the Federal Government, it is assured that the enforcement will require ships and offshore platforms to have total anti-pollution programs.

The need for regulatory compliance has initiated research programs for developing new ways and equipment to meet proposed standards. The regulations have also prompted investigations for monitoring instrumentation and methods for evaluating such systems.

This discussion includes three topics. The first is a description of the effects of sewage discharges. The second topic is a review of applicable regulations. The final topic is a description of sewage treatment systems which are available to the marine industry.

THE POLLUTION ASPECTS OF SEWAGE WASTE DISCHARGES

Sewage in its crude state contains many bacteria some of which are pathogenic. The bacteria vary more in kind than in quantity. Organisms found in soil, water, animal and human intestinal tracts may be found in sewage at different times. The bacteria are divided into two groups, aerobes and anaerobes. The former group is capable of transmitting typhoid, gastro-enteritis, para-typhoid, dysentery and cholera.

When sewage enters a waterway, a series of biochemical changes take place. Bacteria, algae, molds, and protozoa in the waterway decompose the sewage to nitrites, nitrates, sulfites, sulfates, and carbon dioxide. By photosynthesis, green plants in the waterway utilize the end products of decomposition for energy and release products of decomposition for energy and release oxygen to the water. The end result is self-purification of the water. This process progresses slowly and occurs only when a healthy progresses slowly and occurs only when a healthy balance between animal and plant life exists.
Fracturing Design Using Perfect Support Fluids for Selected Fracture Proppant Concentrations in Vertical Fractures
Authors: Harrington Larry , Hannah Robert R.
Published: December 2007

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

This paper presents a method of scheduling proppants in perfect or near perfect transport proppants in perfect or near perfect transport fluids to meet predetermined proppant concentrations in the fracture.

Early attempts at predicting proppant concentrations in fractures failed because of the very poor prop transporting ability of the available fracturing fluids. The formation of a sand bank in the bottom of a vertical fracture completely ruled out prediction of prop concentration based on theoretical leak-off parameters. For this reason such promising parameters. For this reason such promising techniques as partial monolayer propping and high strength proppant tail-ins were abandoned.

The development of cross-linked gel systems and ultraviscous fluids has revived interest in analytical scheduling since proppant transport in these fluids is virtually perfect.

A mathematical model of the fracture is considered with all the factors necessary to predict proppant concentration included. predict proppant concentration included. This development, in contrast to either gross averaging or finite difference solutions, has led to a closed form mathematical solution.

The technique presented allows selection of final fracture proppant concentration based on the fracture conductivity needed to meet design requirements. This concentration requirement and a fracture penetration requirement are used as computer inputs. The final computer printout presents the fluid volume required, the printout presents the fluid volume required, the required proppant amount, the pad volume needed, and a proppant addition schedule. Thus, all factors affecting reservoir improvement are considered by one computer program.

Introduction

When hydraulic fracturing first began, selection of treatment volumes, sand concentration and sand scheduling was strictly an empirical art. Treatment designs relied heavily on experience and subjective judgments of what was possible. The relationships between injection possible. The relationships between injection rate, leak-off coefficients, fracture width, sand concentration, and volume pumped were not completely understood.

After this initial period, several investigators began to develop and apply various analytical tools that helped to rationalize and quantify the techniques used. Significant developments occurred in the prediction of fracture area, fracture width, and productivity improvements. productivity improvements.
Prepack Technique Using Fine Sand Improves Results Of Fracturing And Fracture Acidizing Treatments
Authors: Miller B. D. , Warembourg P.A.
Published: December 2007

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

Use of 100-mesh sand in a prepack stage ahead of the main stages of several types of stimulation treatments has greatly improved results of the treatments. The use of 100-mesh has proved highly effective in improving results of both conventional fracturing and acid fracturing treatments. The technique has been applied successfully in many types of formations in many areas.

Several theories have been advanced concerning the mechanism by which 100-mesh sand improves stimulation efficiency. Probably more than one of the mechanisms contribute. This paper describes the mechanisms by which 100-mesh paper describes the mechanisms by which 100-mesh sand may contribute to better results in various types of formations. Field results of use of 100-mesh sand in different areas and different formations are compared to results of more conventional treatments. Factors that may be involved in the design of the 100-mesh prepack stage are discussed.

Introduction

Originally, 100-mesh sand was used in an attempt to limit penetration of a fracture outward into the reservoir after a desired distance had been reached. The basic idea was to screenout or plug off the fracture at the tip with a pack of the fine sand. Additional fluid injected pack of the fine sand. Additional fluid injected would then tend to widen the fracture and increase conductivity. Whether or not complete plugging actually occurred at the tip of the plugging actually occurred at the tip of the fracture is a matter of conjecture. However, some of the early jobs indicated that some action of the fine sand was contributing to the successful fracturing of reservoirs that had previously screened out. In fact, wells that could not be successfully fractured with small sand (40/60 mesh) would accept large volumes of 10/20 sand at concentrations above 2 – 3 pounds per gallon if a pad of fluid containing 100-mesh sand was used ahead of the main frac stage. Several successful treatments using this technique were completed in the Rocky Mountain area, and it was noted that production results were better even in those areas where conventional fracturing had been successful. Use of the prepack technique with 100-mesh sand grew rapidly, and it is now becoming almost a standard procedure in many areas. It has also proved highly successful in acid fracturing treatments.
Drilling Cooperatives: One Strategy for Reducing Drilling Cost and Risk
Authors: Harris B. W.
Published: December 2007

During a period of rig scarcity, three small, independent operators joined together to present an offshore drilling schedule of sufficient duration to interest a drilling contractor and greatly reduce mobilization costs. Each operator had found that for the market conditions at the time, remote, one-or two-well offshore drilling programs were prohibitively expensive. Also, the short duration of the operators' programs rendered them unattractive to the one drilling contractor capable of doing the work and in the best geographic position to significantly affect program costs. Combining the three drilling programs satisfied the contractor's desire to secure a long-term work contract and promised significant savings in expenditures for the operators. Each operator's drilling program was examined and priorities compared to determine and produce as many common elements in permitting, well design and evaluation needs as possible. The intent was to not only streamline and thereby accelerate certain processes but to maximize purchasing power with suppliers and service companies as well. Reductions in expenditures were anticipated to be 20 percent to 50 percent of total well cost, depending upon the operator. Risk reductions during periods of commonality in the combined program, such as mobilization and demobilization, were expected to be 50 percent and greater. Difficulties arose from conflicts between the common good of the group and each operator's natural self-interest. Because logistical and regulatory pressures caused the combined program to commence before all necessary contractual agreements were consummated, these conflicts were exacerbated.
Results of an Optimization Study on a Major Gas Field Complex
Authors: Miller R.T. , Gattis J.R. , Talbert J.M.
Published: December 2007

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

This paper describes the results of recent optimization study of the Sheridan-Provident City gas field complex. A total of 34 reservoirs and 132 wells were studied in order to develop a plan which would optimize the recovery of the remaining gas-in-place. Production was initiated from these fields in Production was initiated from these fields in the middle 1940's, and they are presently about 75 percent depleted. Sheridan and Provident City are currently characterized Provident City are currently characterized by low pressure reservoirs and complex gathering systems. The gathering systems include:a high pressure, branched flow-line network;a low pressure flowline network with multiple loops;remote field compressors; andlarge central compressor stations.

The problem involved modeling the performance of the reservoirs, wells, gathering systems and compressors in order to predict the field response to several predict the field response to several alternative plans of operation.

The study was carried out by use of a digital computer program which can simulate the conditions existing during production of one or more gas reservoirs connected through a common surface gathering system. The program is capable of simulating both pure program is capable of simulating both pure depletion drive reservoirs and reservoirs having some degree of pressure support either from the expansion of rock and connote water, or from the influx of water from a communicating aquifer, or both. The surface gathering system can be looped and/or branched. Compressors can be simulated at any point in the gathering system and can be added or removed at any preset time. Two-phase flow is modeled in the gathering system and the production tubing, while semisteady state, single-phase flow is modeled in the reservoirs.

This paper demonstrates that, even in the case of complex, mature fields, the use of sophisticated engineering techniques can increase the remaining recoverable gas reserves.

PURPOSE AND SCOPE PURPOSE AND SCOPE The primary objective of this study was to formulate a plan which would optimize the recovery of the remaining Sheridan and Provident City gas reserves. Provident City gas reserves.
A Two-Dimensional Mathematical Model of the Underground Coal Gasification Process
Authors: Magnani Charles F. , Ali S.M. Farouq
Published: December 2007

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

A two-dimensional mathematical model of the underground coal gasification process is developed, and is used to study the effect of the process variables on the total heat recovery by the gasification process.

The model simulates the stream method of underground coal gasification, using the producer gas stoichiometry. Specifically, producer gas stoichiometry. Specifically, reaction kinetics and heat and mass transfer are considered in a horizontal circular channel in a coal seam. Air is injected at one end, where the coal seam is ignited. The carbon dioxide formed is reduced to carbon monoxide farther downstream. The mathematical equations describe the conduction and generation of the heat at the surface of the coal, convective heat transport by the gas stream, and gas phase mass transfer of the chemcial species. The equations were solved analytically, obtaining a closed form solution, which was employed for studying the process, for a variety of operating options.

The model is unique in that it considers heterogeneous, intermediate combustion, i.e. the reaction zone temperature is not high enough so that diffusion controls the process, nor is it low enough that reaction kinetics dominate.

It was found that the use of oxygen or enriched air is superior to air as the gasification agent, i.e. the total heat content of the produced gas increases with an increase in the oxygen concentration. An increase in the mean axial velocity leads to an increase in the total heat content of the produced gas up to a certain point, beyond which a decrease is observed. The gasification process is more effective in small diameter channels. Results obtained show that the production of carbon monoxide is critically dependent on the gasification agent, the reduction zone temperature, the average gas velocity, the contact time for the reduction reaction, and the channel diameter for a given reactivity of coal.

Introduction

Underground gasification of coal has received a great deal of attention in the past, as the numerous publications and field tests indicate. Currently, there is renewed interest in the process, first on account of its environmental advantages, and secondly, because the economics of the process are likely to be more favorable now than was the case in the earlier field tests. The process has not been analyzed and modeled mathematically to any great extent. In a previous publication, the authors presented the development of a mathematical model of the process, assuming producer gas stoichiometry, homogeneous reaction producer gas stoichiometry, homogeneous reaction kinetics, and one-dimensional heat and mass transport. This paper extends the previous model to consider two-dimensional mass transport, and heterogeneous reaction kinetics.
Evaluating Reservoir Production Mechanisms and Hydraulic Fracture Geometry in the Lewis Shale, San Juan Basin
Authors: Frantz J.H. , Fairchild N.R. , Dube H.G. , Campbell S.M. , Christiansen G.E. , Olszewski Adam J.
Published: December 2007

This paper was prepared for presentation at the 1999 SPE Annual Technical Conference and Exhibition held in Houston, Texas, 3–6 October 1999.
Erosion of Perforation Tunnels in Gas Wells
Authors: Vriezen P.B. , Spijker A. , van der Vlis A. C.
Published: December 2007

Vriezen, P.B., Member SPE-AIME, Koninklijke/Shell Exploratie en Produktie Laboratorium, Spijker, A., Koninklijke/Shell Exploratie en Produktie Laboratorium and van der Vlis, A.C., Member SPE-AIME, Koninklijke/Shell Exploratie en Produktie Laboratorium

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

The stability of a perforation depends on its geometry, and on both the mechanical strength and the effective-stress distribution in the vicinity of the perforation.

Erosive action of the gas flow into and through a perforation may gradually increase the perforation diameter. This effect could considerably reduce the mechanical stability of such a perforation.

This paper presents an experimental evaluation of the relative importance of erosion on perforation stability. It describes a special triaxial cell, which permits axial and radial flow through a thick-walled cylinder of the core material being tested. The other components of the closed-loop gas-flow system used including gas-humidifying equipment and a sand-particle detector, are outlined. With this unique set-up, experiments have been performed under simulated downhole conditions on samples selected from the Rotliegendes sandstone formation of the Groningen gas field.

It appeared that, for a given hardness of the sandstone being investigated, perforation stability is mainly determined by the effective stress level. Erosion was found to have only a minor influence on perforation stability.

Introduction

A substantial amount of the world's oil and gas production is from reservoirs requiring some type of sand control. The decision whether a sand-exclusion technique should be incorporated in the design of a well completion, is generally based on core description and/or the outcome of production tests. If the formation is a completely unconsolidated sand, this decision is evident. More difficult to decide on are the formations of friable nature, in particular when production facilities limit proper simulation of future production rates and production conditions, production rates and production conditions, such as depletion of reservoir pressure and the onset of water production. Efficient development and management of these types of reservoirs would certainly benefit from more quantitative techniques to appraise the necessity of sand-exclusion methods.
Well Test Characterization of Wedge-Shaped, Faulted Reservoirs
Authors: Charles D. D. , Rieke H. H. , Purushothaman R.
Published: December 2007

Two south Louisiana offshore, wedge-shaped reservoirs were interpreted using pressure-buildup responses by comparing the results from simulated finite-element model studies. The importance of knowing the correct reservoir shape is briefly discussed and how it is used to interpret the generated boundary pressure responses. Two different 3-D computer models incorporating different wedge-shaped geometries simulated the test pressure-buildup response patterns. Variations in the two configurations are topologically expressed as a constant thickness and a non-constant thickness, smooth surface, wedged-shaped reservoir models. The variable thickness models were pinched-out up-dip at one end and are faulted at the other end. Numerical well test results demonstrated changes in the relationships between the pressure derivative profile, wellbore location, and the extent of partial penetration in the reservoir models. The wells were placed along the perpendicular bisector (top view) at distances starting from the apex at 5, 10, 20, 40, 50, 60, 80, and 90 percent of the reservoir length. Results demonstrate that boundary distance identification (such as distance, number and type) solely on the basis of the log-log derivative profile in rectangular and triangular wedge- shaped reservoirs should be strongly discouraged. Partial penetration effects in wedge reservoirs are highly dependent on the wellbore location relative to the wedge and adds to the complexity of well test data analysis.
Lateral Proppant Distribution: The Good, the Bad, and the Ugly of Putting Frac Jobs Away
Authors: Aud W. W. , Poulson T. D. , Burns R. A. , Rushing T. R. , Orr W. D.
Published: December 2007

This paper shows proppant induced pressure increase (i.e., "tip screenout", "pack", "body pack", etc.) can relate to restricted vertical and lateral proppant distribution in hydraulic fractures. We discuss a way of interpreting the character of the pressure response during the proppant stages of a fracture stimulation. The pressure response during the proppant stages will determine the quality of the production response and the level of success that is achieved. The technology presented has been found to apply to all rock types and most formations.

This area of study is based upon common sense observations and extensive engineering. It fits the reservoir engineering of the producing character and advanced fracture treatment pressure interpretation on over 1,000 wells. When early proppant bridging occurs in the fracture, the lateral and vertical proppant distribution adjacent to the pay interval can be negatively affected. This results in less effective stimulation because the pay interval, both vertically and laterally, is not effectively propped. The fracture stimulation may have been "put away"; but the negative aspects of how the stimulation was designed and implemented may have a significant affect on the resultant production response.

To lay the basis for additional thought and investigation, there is discussion about deficiencies in overly simplified pretreatment mini-fracture analysis procedures. These analysis methods are not focused on the proppant induced friction character, and therefore can not optimize fracture length. An evolved approach is presented, that addresses leakoff, fracture geometry, and proppant induced friction, to optimize the proppant distribution, and overall stimulation of the pay interval.
Description and Modeling of a Complex Fluid Column in the Santa Barbara and Bosque Fields, North Monagas State, Venezuela
Authors: Smith Richard W. , Trias Olimpia , Yemez Ivan , Bard Wade A. , Corredor Jairo
Published: December 2007

The Santa Barbara and Bosque (SB/BSQ) fields, located in northern Monagas State of Venezuela, are in an area of the largest and most prolific oil fields in Venezuela and currently produce nearly 1 million BOPD. The fields are operated by Petroleos de Venezuela, S.A. (PDVSA). The proven SB/BSQ hydrocarbon column is more than 6,000 feet thick. The vertical compositional variation creates a complex system where relatively low yield condensate gas changes to high yield condensate, near critical fluid, volatile oil, and finally, highly under saturated oils. The fluid system is complex and area differences exist because of structural compartmental-ization. Original field management strategies identified the high potential of increasing reserves by high-pressure injection of produced gas. Modeling of the complex interactions of injected gas is important, thus a full and detailed study of the PVT samples, evaluation of area fluid distributions, and the definition of an equation of state to allow reservoir modeling were performed. This paper documents the effort of 1998 and the ongoing process to define an Equation-of-State (EoS) to meet reservoir modeling and management objectives.
Advanced Fractured Well Diagnostics For Production Data Analysis
Authors: Poe B. D. , Conger J. G. , Farkas R. , Jones B. , Lee K. K. , Boney C. L.
Published: December 2007

New analysis procedures are presented for analyzing the production data of fractured wells in low permeability reservoirs to quantify estimates of the reservoir effective permeability, effective fracture half-length, and average fracture conductivity. The rate-transient based analyses reported in this paper have been used to analyze the production performance of over 200 wells in low permeability reservoirs in North America.

Direct comparisons of the fracture properties resulting from conventional crosslinked fluid fractures and low viscosity base fluid ("Water-Frac") treatments in direct offset wells clearly demonstrates that more effective fractures are created in low-permeability reservoirs using the higher viscosity fracturing fluids and large proppant volumes to achieve higher conductivity fractures with greater effective half-lengths than are achieved with "Water-Fracs" with little or no proppant.
New Concentric Annular Packing System Limits Bridging in Horizontal Gravel Packs
Authors: LaFontaine Jackie , Sanders Mike , Hailey Travis , Mickelburgh Ian , Lord David
Published: December 2007

Although horizontal completions in unconsolidated sands have become common, challenges associated with the inflow of formation sand during production still exist. The industry has responded to the challenge of controlling formation sand flow in horizontal wells by advancing the technology currently used in vertical wells. Wells with record-breaking production have been successfully completed with this technology, but failures have also occurred because of problems associated with imperfect gravel placement. If excessive leakoff is encountered during gravel placement, or sand concentrations fluctuate excessively during the treatment, bridges can form, resulting in incomplete packing. As the current technology is increasingly challenged with longer horizontal intervals and/or lower bottomhole pressures, further development will be required for complete, effective gravel placement. This paper discusses the concept and initial experimental results of a project designed to further develop the technology of horizontal gravel-packing.
A Comparison of Jet Perforating Services Kern River Field
Authors: Keese J.A. , Oden A.L.
Published: December 2007

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

In 1974 and 1975 the authors supervised the perforation of 184 steamflood production and perforation of 184 steamflood production and injection wells. The large number of completions plus the combination of shallow depth (less than plus the combination of shallow depth (less than 2,000 feet) and low reservoir pressure (less than sixty psia) provided an opportunity to compare quantitatively the performance of different perforating companies. perforating companies. All perforating guns were inspected immediately after firing. The numbers of misfires, blown port plugs, and misaligned charges are tabulated. Significant variations in performance are noted between perforators. As a followup, inflatable impression packers were run in a number of the wells. The variation in perforation diameter is presented statistically.

The four companies perforated wells on the same lease during the years 1970 to 1972. The subsequent productions of these wells are compared. Two of the perforators shot six adjacent steamflood wells in 1974. The production characteristics of these wells are also compared.

Introduction

During recent years, there has been a recurring controversy about the practice of bidding large perforating jobs. The perforation of a well is perhaps the most critical phase of completion. Consequently, operators experience misgivings in automatically awarding jobs to perforating companies offering the least perforating companies offering the least expensive price. Two alternatives are:Restrict the bid to only those perforators giving superior performance.Award jobs only to the best perforator no matter what the cost.

A requirement of either possibility is the existence of some method to evaluate quantitatively perforating company performance. The procedure must be simple to employ as well as relatively inexpensive or the purpose of the endeavor is lost. This paper explains such a comparison program and describes it and the results. It should be noted that the procedures discussed here are applicable to a specific region and type well completion.

COMPLETION PROCEDURES

The Kern River Field consists of unconsolidated Pleistocene deposits located at depths above 2,000 feet. These channels and delta sands have thicknesses ranging from five to fifty feet.
A Practical and Efficient Uplayering Method for Scale-Up of Multimillion-Cell Geologic Models
Authors: Li D. , Beckner B.
Published: December 2007

Geophysicists, geologists, and reservoir engineers can now routinely build reservoir geologic models with ten million geologic cells and more than one thousand geologic layers. This explosion in reservoir detail capability presents new challenges for existing upscaling methods. Uplayering (the first step of upscaling) is a technique that provides reservoir engineers with optimal geologic layer-grouping schemes for simulation model construction. Much uplayering is still done by hand by reservoir engineers. Even though some advanced methods can provide automatic tools for uplayering, they are limited in the applicable model size and are also computationally expensive. This paper presents a practical and efficient method for uplayering of multimillion-cell geologic models. The proposed method defines a displacing front conductivity, a combination of porosity, permeability, and facies (in terms of relative permeability, endpoint saturation, and various facies rules), as the uplayering property. Use of the new property ensures that the most important geologic features for fluid flow simulation can be preserved after uplayering. The new method utilizes a residual optimization technique to determine the optimal geologic layer-grouping scenario for a given number of simulation layers. The method is so efficient that multiple optimal grouping scenarios, from the one simulation layer model to the model consisting of all geologic layers, can be generated in a short time, allowing the inspection of all possible combinations of layer-grouping scenarios. A residual curve (the difference of the defined property between the fine-layer and coarse-layer models) is produced from exhaustive analysis of all possible layering combinations. Using the residual curve, engineers are able to determine the number of simulation layers needed based on their tolerance of possible loss of fine-layer geologic features. The uplayering method has been successfully employed in most of major reservoir study projects in Mobil and results from three of these studies will be included in this paper.
Enhancing Production in Multizone Wells Utilizing Fracturing Through Coiled Tubing
Authors: Spady D. W. , Udick T. H. , Zemlak W. M.
Published: December 2007

Zonal stimulation using hydraulic Fracturing, which typically was performed through jointed pipe, has recently been performed with Coiled Tubing. In the last two years, over one thousand fracturing treatments in North America have been executed using this method. Coiled Tubing allows a method of stimulating individual, bypassed or marginal zones, using positive zonal placement of proppant. Coiled tubing also gives the advantage of treating a well under pressure without introducing a kill fluid to the formation. In the Appalachians, where multiple small zones exist in one wellbore, this technology can provide significant cost savings by reducing trips to the well, equipment on location, and rig time to move downhole hardware. Coiled tubing fracturing eliminates the need for bridge plugs and allows stimulation of multiple zones in a single trip to the well. Ultimately the size of a stimulation treatment can be re-engineered because of the positive isolation for each specific zone in the wellbore. The overall effect to the producer is greater production at a lower total cost.
Effect of Abnormal Pore Pressure on Deep Water Drilling
Authors: Andriesse D.
Published: December 2007

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

This paper was prepared for the SPE-European Spring Meeting 1976 of the Society of Petroleum Engineers of AIME, held in Amsterdam, The Netherlands, April 8–9, 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 PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal, 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.

Drilling operations in deep water are more constrained than on land. Apart from sophistications concerning control systems, hardware, etc. this is caused by the convergence of mud and formation strength gradients, the weakness of shallow formations, the possible small margins between formation strength and pore pressure and the mud weight pore pressure and the mud weight capacity of the riser system.

As a result of these constraints, the ultimate well depth would be severely limited when encountering abnormal pressures. In order to investigate this pressures. In order to investigate this problem a survey was carried out on problem a survey was carried out on formation strength and abnormal pore pressure occurrence. The outcome of it pressure occurrence. The outcome of it suggests that the majority of deep water wells can be drilled with conventional casing systems.

Mud weights required to control abnormal pore pressures will cause fracturing of the formation more readily in deep water than in land operations. A solution to this problem has not yet been found.

Consequently prediction and early detection of abnormal pore pressures is of greatest importance for deep sea operations.

Introduction

Formation strength, expressed as fracture pressure, is lower at any given depth below derrick floor in deep water than in shallow water or land drilling operations. This is caused by the fact that in wells located offshore a part of the overburden consists of water rather than of sediments.

As a result there is an interval above the intersection of the formation strength and mud gradients in which the mud pressure exceeds the formation strength.

In order to avoid fracturing, casing will have to be set prior to raising the mud weight.