bluuebunny/crossref_metadata_2025 huggingface dataset:
In-Depth Fluid Diversion by Pre-Gelled Particles. Laboratory Study and Pilot Testing.
Authors: Coste J. -P. , Liu Y. , Bai B. , LI Y. , Shen P. , Wang Z. , Zhu G.
Published: December 2007

This paper introduces a new diverting agent that has been developed to control water production in high salinity, high temperature reservoirs. Several dry gels have been crushed and sieved to obtain different cuts of gel particles. The dry powdered gel particles swell in water to give a stable suspension. The swollen pre-gelled (PG) particles do not dissolve in water and can move inside the porous media. Results presented here include test pilots and laboratory experiments. PG particles have been successfully used in two recent pilot tests in Shengli Oilfield, China. Micromechanisms of particle motion and oil mobilization have been studied through transparent glass micromodels experiments. Core tests have also been conducted to verify the selective placement of the particles. According to the experimental laboratory results we can conclude that the mechanisms responsible for the enhancement of oil production are the following:

After swelling and under a high pressure gradient (near the wellbore), the pre-gel particles can deform to pass through small pore throats, ensuring displacement of the residual oil. When the pressure gradient is too small (away from the wellbore) the particles plug the pore throats changing the flow pattern inside the reservoir.

In addition, as the gelation is accomplished before the injection, the PG particle technique overcomes some of the most important problems which can be encountered by classic gel treatments: lack of control of the gelation time, lack of control of the stability of the gel formed or ungelation due to adsorption, dilution or degradation of the polymer or pH change. Furthermore, due to these specific characteristics, this process can be used in oilfield environment that would prevent the in-situ gelation of a classical gelant solution.
Soft Computing for Intelligent Reservoir Characterization
Authors: Tamhane D. , Wong P. M. , Aminzadeh F. , Nikravesh M.
Published: December 2007

This paper presents an overview of soft computing techniques for reservoir characterization. The key techniques include neurocomputing, fuzzy logic and evolutionary computing. A number of documented studies show that these intelligent techniques are good candidates for seismic data processing and characterization, well logging, reservoir mapping and engineering. Future research should focus on the integration of data and disciplinary knowledge for improving our understanding of reservoir data and reducing our prediction uncertainty.
Capturing Depositional Uncertainty: Sunrise-Troubadour Giant Gas-Condensate Fields
Authors: Seggie R. J. , Ainsworth R. B. , Arditto P. , Burns F. , Johnson D. A. , Koninx J. P. M. , Stephenson P. M. , Thompson J.
Published: December 2007

The Sunrise-Troubadour giant gas-condensate fields lie on a massive, broad, low-relief structure 75km long and 50km wide. The fields have a gross reservoir thickness of 80m. They are located on the northwestern boundary of the Australian Plate and form the basis of a proposed green-field LNG project and an Australian domestic gas development.

Statistical volumetric analysis has shown that reservoir quality, distribution and Net-To-Gross ratio (NTG) are the main static uncertainties affecting Gas-Initially-In-Place (GIIP). These parameters are a function of the environment of deposition of the reservoir interval. The low average NTG in some wells (as low as 30%) indicates potential for depositional heterogeneity which can impact dynamic fluid flow through the reservoir. Depositional modelling has therefore been a major focus for field evaluation and appraisal.

The reservoir interval was deposited in a marginal marine setting on a slowly subsiding, broad, low-relief shelf. The overall retrogradational character of the reservoir interval is illustrated by the upward increase in the open marine character of the interbedded shales. There are two major relative sea level falls interpreted which resulted in the deposition of incised-valley and sharp-based, forced regressive shoreface deposits. These sandbodies form the major reservoir units in the fields. Highstand and transgressive deposits are characterised by relatively thin and discontinuous sandbodies.

In order to fully capture the depositional uncertainty inherent in a field of this scale which only has limited well control (six wells), three groups consisting of sedimentologists, stratigraphers and biostratigraphers have independently interpreted the core and wireline data. The result was three different depositional interpretations.

From these interpretations a most likely depositional model was developed. Low and high case 3-D depositional models were generated by varying NTG and sandbody correlatibility and geometries. The adjustment of these parameters reflected the range of depositional interpretations from the three individual expert groups.

These models form the basis of multi-scenario reservoir simulation studies which indicate that development options for these fields are technically robust for the range of perceived subsurface scenarios.
Understanding and Modeling Water Free Production in Transition Zones: A Case Study
Authors: Parker A. R. , Rudd J. M.
Published: December 2007

When production testing an oil reservoir in the oil-water transition zone it is usual to expect water production. This paper shows field examples where dry oil production is encountered in the middle of oil-water transition zones in a non-fractured, mono-modal and essentially homogeneous carbonate reservoir. Whilst it is simple to replicate this behavior in numerical simulators, the reason behind this phenomenon is not so obvious. This paper pulls together current understanding with regard to wettability, capillary pressure, percolation and adsorption through films in order to explain the mechanism behind the phenomenon. Through a greater understanding of the cause of the anomaly it is anticipated that knowledge of pore scale processes will lead to improved recovery methodologies.

The Field, which is the subject of the case study, is in the appraisal stage (6 well penetrations, no production) and is composed of a series of stacked Carbonate reservoirs located in shallow water offshore of the UAE. The entire oil column has been cored, extensive Mercury Injection data was available for analysis and the oil-water transition zone extends across 70% of the oil column.
Integrating Resistivity Data with Production Data for Improved Reservoir Modelling
Authors: Wang Pengju , Horne Roland N.
Published: December 2007

This work deals with the problem of estimating reservoir permeability and porosity distribution from multiple sources, including production data and well logging data. The work focuses on integrating long-term resistivity data into the parameter estimation problem, investigating its resolution power both in the depth direction and in area.

The resistivity logging tool considered in this project is a new tool proposed for permanent installation. The tool is installed in the cement around the well when the well is completed, and is capable of recording the long-term resistivity variation around the wellbore.

In this work, the Poisson equation with mixed boundary condition was used to model the infinite potential field around the resistivity logging tool. The behavior of the reservoir was modeled with a standard three-dimensional, two-phase, black-oil model. The resistivity response simulator was integrated into the flow simulator through Archie's law.

The Gauss-Newton algorithm was used to solve the inverse problem. This algorithm requires the calculation of the derivatives of the observation data with respect to the unknown parameters. These derivatives are called the sensitivity coefficients.

By running several simple inverse problems, it was concluded that the resistivity data has high resolution power in the depth direction and is capable of sensing the areal heterogeneity.
Development of Operations Reference Plan (ORP) for Asset Management
Authors: Sulaiman Salahuddin , Husin Muhammad Taufik
Published: December 2007

The business processes for oil and gas production comprise exploration, appraisal, development, production, sales and abandonment. Typically a field has an economic producing life of 15 to 25 years compared to 3 to 7 years to explore, appraise and develop. Production is an important phase in which hydrocarbons are produced and assets are maintained until the economic limit is reached. Oil production from mature fields will continue to deplete while water production increases. Produced water is to be disposed off in an environmental friendly manner meeting regulatory requirements. Artificial lift to supplement the reservoir energy is increasingly needed to sustain production. Facilities are aging and maintenance activities are expected to increase and hence cost in materials, logistics and human resources. The emphasis is to manage the producing assets in the most profitable manner, i.e. maximize the return on investment through improvement in performance and cost reduction over the complete life cycle. Very often it requires application of new technologies to contain the operating costs and increase oil and gas production. An effective, integrated planning system is required to improve the management and control of operational activities in each asset, and to optimize development over the full life cycle of the asset. To this end, the Operations Reference Planning (ORP) concept was developed as an integrated multi-disciplinary business model. It provides a framework system that will allow various future development scenarios to be tested, and to establish a clear understanding of the parameters that will affect return on investment with proper regard for safety and the environment. An ORP has been developed for the Baram field, one of the nine producing fields in the Baram Delta area, offshore Sarawak, Malaysia, operated by PETRONAS Carigali Sdn Bhd (Sarawak Operations). The Baram field, which contains billion barrels of oil initially in place, is one of the largest producing fields in the area. The field came on stream in 1971 and is still producing merrily after almost three decades of production. Furthermore, there is substantial scope for additional development that will prolong the field life well into the new millennium. This paper discusses PETRONAS Carigali Sdn Bhd's (Sarawak Operations) experience in developing the Operations Reference Plan for the Baram field. It highlights the methodology undertaken, organizational and resources requirements, roles and responsibilities of key positions, multi-disciplinary team approach from subsurface to surface, sharing of good practices, production enhancement and cost reduction initiatives to prolong the field economic life.
Dynamic Model of Wormhole Formation Demonstrates Conditions for Effective Skin Reduction During Carbonate Matrix Acidizing
Authors: Fredd C. N.
Published: December 2007

The success of carbonate stimulation treatments is highly dependent upon the formation of conductive flow channels, or wormholes. Success requires wormhole formation during matrix acidizing treatments and lack thereof during fracture acidizing treatments. The structure of the wormhole channels, which varies significantly with flow conditions and acid/mineral properties, ultimately controls the effectiveness of a stimulation treatment. This paper describes a dynamic model of wormhole formation that accounts for wormhole structure based on the Damköhler number. It addresses the issue of scaling laboratory data to the field by including the effects of fluid loss and wormhole competition. The model predicts skin evolution based on basic input parameters and is used to demonstrate matrix acidizing strategies for optimum skin reduction with several acid systems.

The results demonstrate that, under typical treatment conditions, conventional matrix treatments with straight HCl cause face dissolution and provide little reduction of skin. Under the same conditions, alternative fluids such as weak acids and emulsified HCl create dominant wormhole structures that penetrate deep into the formation. While these fluids are more effective than straight HCl (especially at high temperatures and low injection rates), additional injection strategies can be used to increase the depth of penetration and, in turn, improve skin reduction. Injection strategies such as increasing the injection rate or decreasing the rate of dissolution (by changing the fluid properties) promote deeper penetration of wormholes. These injection strategies rely on maintaining an optimum Damköhler number for effective wormhole formation during matrix stimulation treatments. The model also applies to the selection of fluid properties to control wormhole formation during fracture acidizing treatments.
What Does Deming Have To Do With Oil and Gas?
Authors: Matthews V. , Linger D. B.
Published: December 2007

Deming's principles of management are often regarded by individuals in the petroleum industry as being applicable to manufacturing operations, but not to E&P activities. The argument usually asserts that E&P activities are so varied that Deming's method of analyzing "the system" can't be used in the oil & gas business.

The experience of one small, independent company shows quite the opposite, i.e. that Deming's methods are indeed quite useful in many areas of E&P operations and they can lead to greatly improved operations. A specific example regarding the inability of getting wells drilled according to a budgeted schedule serves to illustrate how several of these principles applied to the problem resulted in vastly improved performance.
Through-Life-Cost (TLC) Management: The Key to Reducing OPEX
Authors: Flatt Robert N. , Condic Sam , Marks Vicki
Published: December 2007

Increasing sensitivity to crude price fluctuations will require operators to reduce costs for drilling, completion and production operations. A key component of this strategy is the collaborative management of equipment assets by operators and suppliers to reduce cost over the complete life cycle of the equipment. This paper analyzes benefits derived from TLC Management Programs undertaken with customers worldwide to reduce operating expenses.
Characterization of the Dynamic Fracture Transport Properties in a Naturally Fractured Reservoir
Authors: Baker Richard O. , Contreras Ruben A. , Sztukowski Danuta
Published: December 2007

In characterizing and modeling the performance of naturally fractured reservoirs (NFR), fracture length and fracture connectivity (permeability) are often assumed to be constant. A number of field tests done on Spraberry Trend wells suggest this assumption is not always true for NFR.

Pressure transient tests and decline analyses have been used to determine permeability, skin, fracture connectivity and average reservoir pressure for the Spraberry Trend reservoir of West Texas. It has been hypothesized by L. Elkins1 that fractures open and close due to pressure effects. In order to better understand these effects and fluid movement pathways, a number of specialized pressure transient tests have been conducted and analyzed in the E.T. O'Daniel Unit of Spraberry. This included constant pressure decline rate tests, build up tests, step-rate tests, falloff tests and a multi-well interference test, carried out so as to minimize the risk of induced fractures which can cause reduced sweep efficiency and fluid losses to other non pay zones. Results indicate that fracture systems are very stress sensitive in the Spraberry formation, with fractures opening and the effective permeability increasing at high injection rates (in addition, reservoir flow simulation has also confirmed that permeability is stress sensitive).
Interwell Seismic Data for Reservoir Characterization
Authors: Justice J. H. , Woerpel J. C. , Watts G. P. , Waddell W.
Published: December 2007

As part of a DOE Class II Oil project, a wide variety of data were acquired in a Permian Basin oil field. This included core, log and petrophysical data, as well as interwell borehole seismic data. Borehole seismic data was acquired to provide baseline surveys for future CO2 monitoring, but also to investigate its use for high resolution reservoir characterization. A method was developed to derive detailed porosity and permeability maps between wells using the log, core, and interwell seismic data together with certain petrophysical relationships. The resulting interwell porosity and permeability maps provide a natural basis for extracting statistics, such as variograms, needed for geostatistical reservoir modeling and simulation. This procedure provides an important new alternative for obtaining spatial statistics needed for geostatistical reservoir studies.
Advances in Deep-Penetration Density Logging
Authors: Chapin David A. , Ander Mark E.
Published: December 2007

The borehole gravity logging tool, used as a deep investigation density method that can image through casing, is enjoying a renaissance. Originally designed in the early 1970s, the tool suffered from hardware limitations, such as size, deviation, and speed, which now keeps it out of the majority of wells drilled. These artificial limitations can now be overcome with modern engineering and new electronic components technology that was unavailable a few years ago. New advances in gimbals and leveling move borehole gravimetry forward into the 21st century. The fundamental principles of borehole gravity remain a sound and valuable technology for all phases in the life of an oil field. Numerous examples and case studies can be cited which attest to borehole gravity's value in exploration, formation evaluation, reservoir monitoring, and missed pay opportunities.
Enzyme Breaker Technology Increases Production, Grayburg-Jackson Field, Southeast New Mexico: A Case History
Authors: Malone Mark R. , Nelson Scott G. , Jackson Randy
Published: December 2007

The subject matter of this paper will describe organoborate fluid systems in combination with guar specific enzyme breakers, their application, and how they were used to improve production in the Grayburg-Jackson field of SE New Mexico. Furthermore, the paper will discuss the completion objectives in the Grayburg-Jackson field as they relate to stimulation treatments and explain how wells were normalized for the purpose of this study. Finally, production results will be examined to compare organoborate/guar specific enzyme breaker combinations verses monoborate fluid systems with non-specific breakers.
A Pulsed Neutron Analysis Model for Carbon Dioxide Floods: Application to the Reinecke Field, West Texas
Authors: Odom Richard , Hogan Phil , Rogers Carroll , Steckel F. Merle
Published: December 2007

Rienecke field is one of a series of fields in the Horseshoe Atoll of the Midland Basin. This carbonate reservoir has fairly good lateral and vertical continuity and is confined in a dome-like structure. A gravity-stable crestal carbon-dioxide flood was begun in 1997 by injection into five wells at the high point of the structure. Pulsed-neutron logs run through casing provide a method to monitor reservoir dynamics and locate oil production targets.

The first step in developing a cased-reservoir analysis model is to estimate the carbon dioxide content. This is done by correlation of the cased-hole neutron and density porosities from the pulsed-neutron system. In developing a three-phase saturation model (oil, water, carbon dioxide)the effects of the carbon dioxide on the oil and water saturation measurements must be determined. Computer simulations of tool response are utilized in conjunction with field data to develop the model and the uncertainties in the saturations.

An example log and analysis demonstrate the capabilities of the reservoir analysis model. The analysis results are compared to production and historical data for the field.
Efficient Approach for Well Calibration in Reservoir Simulation After a Successful History Match
Authors: Siu Alan L. , Salamah Majid M. , Al-Khatib Mohammed H.
Published: December 2007

A systematic and efficient approach for well calibration against wellhead pressure has been developed and verified for two reservoir simulators. The new approach integrates the producing well conditions into the flow table generation step so that the well productivity can be matched while generating the flow table. The main advantage of this approach is that most of the calibration effort is spent on individual wells, which requires less computational effort. Once the appropriate flow tables are generated, it only takes a few reservoir simulation runs to calibrate all the wells in the model. The computer applications based on this approach yield significant cost savings by reducing the project time from weeks to days, and by improving the quality of the well calibration.
Connectivity and Permeability in Fracture Networks Obeying Power-Law Statistics
Authors: Rossen W. R. , Gu Y. , Lake L. W.
Published: December 2007

Recent research on naturally fractured reservoirs suggests that microfractures and megafractures are all part of a single population that shows a power-law relation between frequency of occurrence and fracture aperture or length. The objective of this work is to investigate the effective permeability of fracture networks whose fractures obey power-law scaling relations.

For the simple case where each fracture extends through the region of interest, we present a formula that relates effective fracture-network permeability to the distribution of fracture apertures. In this simple case, the effective permeability of the region is dominated by the single largest fracture in the region.

In reality, of course, flow through fractures depends on whether fractures interconnect. Connectivity at one length scale does not relate simply with connectivity at another scale, if fracture properties obey power-law scaling relations. Fracture populations based on frequency/length scaling exponents derived from field data are not guaranteed to interconnect on either the microscopic or megascopic scales. Computer-capacity limitations make it difficult to include enough fractures to model a region even the size of one reservoir grid block. Clustering of fractures into swarms appears to be the key to fracture interconnectivity.
Importance of Completion Design Considerations for Complex, Hostile, and HPHT Wells in Frontier Areas
Authors: Hahn D. E. , Pearson R. M. , Hancock S. H.
Published: December 2007

As upstream oil and gas exploration and production companies search for new opportunities, much deeper wells are being drilled and completed. In addition to greater depths, an increasing number of wells are being drilled and completed in much more hostile downhole environments. These very complex wells are frequently drilled in frontier areas around the world, including the Western and Northern Canadian foothills and coastal areas. Where pressures exceed 10,000 psi (69 MPa) and temperatures surpass 300°F (149°C), wells are generally termed High-Pressure/High-Temperature (HPHT) completions.

The stresses resulting from the combination of high axial loads and pressure differentials begin encroaching on materials limitations of standard subsurface equipment. This paper provides an overview of an engineering design methodology that can be used during the planning of deep, difficult, or complex wells. The importance of numerous design considerations and realistic, clearly defined load cases will be emphasized.

High temperatures cause the well to operate with either significant pipe movement, or high compressional loads at the packer, particularly when these high temperatures are combined with higher operating pressures. The increased well depths, usually with accompanying deviations from vertical, also increase mechanical and fluid friction. These situations require a rigorous engineering analysis with the aid of modern thermal and stress analysis software.

Traditional uniaxial and biaxial working stress designs are convenient and usually adequate for shallower, lower temperature/pressure wells. However, the severe conditions considered within this paper require state-of-the-art triaxial design software. Examples within the paper will demonstrate how the results of these simulations can be used for hostile environment tubular selection, including discussion of the importance to properly select and test the tubular connections.

Many failures have resulted from brittle fracture or fatigue rather than yield, because the tendency for the designer is to choose higher yield strength materials that are inherently less ductile and more prone to hydrogen embrittlement. To avoid this, it is better to push the limits of lower strength, ductile materials, which in turn challenges the typical design safety factors. This challenge has lead some major oil companies to develop and use risk based tubular design processes.
Gas Production from Low Permeability Carbonates Enhanced through Usage of New Acid Polymer System
Authors: Metcalf Steve , Lopez Henry , Hoff Charlie , Woo George
Published: December 2007

Gas production from the Strawn Limestone formation in Crockett County, Texas is generally only commercial after stimulation. Historically, the most successful stimulation treatments typically consist of large acid fracturing treatments. Several techniques have been used, including gelled acid, gelled water pads and gelled acid pumped in alternating stages and crosslinked acid systems.

Gelling of acids has been accomplished for years using emulsions to facilitate the addition of polymer to acid to achieve good hydration. Recently, a new emulsion system and polymer were introduced into this area which significantly improved efficiency both in developing fluid properties and operations on location. The micelles of this new polymer emulsion are approximately 1/15th the size of those previously applied. The polymer emulsion uses a highly specific external activator to initiate and promote hydration, dramatically reducing the formation of "fisheyes". In addition, it allows for continuous mix operations on location.

Production results are presented from three wells, showing a 34% improvement in production in which the new polymer system has been used. In addition, production responses to several different treatments are compared, which show crosslinked acid fracture treatments to be the most successful. Treatment details along with a description of the new emulsion chemistry and operational advantages are presented.
Determining Liquid Carry Over in Gas Condensate Production Facilities and Assessing the Flow Regime in the Gas Sweetening Carbon Dioxide Amine Units Offshore on the Sleipner Platform in the North Sea
Authors: Georgie Waleed J. , Nilsen Jan I. , Håland Trygve , Solheim Erik , Lyth Chris J.
Published: December 2007

The produced gas from Sleipner West field area contains up to 9.5 % carbon dioxide 1, 2 and is almost free of hydrogen sulfide. Gas handling facilities on the platform were designed to reduce the level of CO2 to the export criteria of 2.5%. During the start up phase of production and the three years of operation period that followed, the required level of carbon dioxide removal of 2.5% was not achieved, and in most cases the CO2 level in the gas export was averaging 3.5% or higher. Although the slightly higher level of CO2 in the gas export did not cause any major problem, since the export stream from Sleipner West production is mixed up with relatively carbon dioxide free gas (less than 1.0%) from the main Sleipner East production area, it was important to provide complete flexibility in the Sleipner West gas treatment facilities to meet the export criteria of 2.5% CO2.

Poor performance of the amine absorbers in removing the CO2 in the gas phase was thought to be related to the condensate build up in the amine solution. Significant foam build up in the amine absorbers was a good indication of condensate build up caused by carry over and / or condensate retrograded in the pipe work between the different vessels.

Organic, aqueous and gas based radioactive tracers were used extensively in the gas processing facilities and the carbon dioxide removal gas sweetening plant on Sleipner West treatment production platform (SLT) in the North Sea. The use of radioactive tracer techniques within the platform facilities provided semi quantitative data on the level of the liquid carry over from the condensate stabilization process train to the gas plant over a period of three years. In addition, by utilizing the technique in the amine absorbers within the carbon dioxide removal plant, a clearer picture of the flow regime within the tower emerged and was developed. Using the data generated from these studies, as well as plant and system performance data, a full assessment of the poor CO2 removal efficiency was carried out in order to identify the potential problem and determine the required and necessary modifications to the treatment facilities on SLT.

A combination of plant offshore studies, process simulation, laboratory analysis and radioactive tracer studies were utilized to identify and rectify the problem. The data generated from the latter studies were considered an important part in developing an understanding of the problem in the process system on Sleipner West treatment plant. This paper addresses the approach used in utilizing the radioactive tracer techniques in providing a tool for determining carry over and flow regime within the process vessels.
Development of an Intelligent Systems Approach for Restimulation Candidate Selection
Authors: Mohaghegh Shahab , Reeves Scott , Hill David
Published: December 2007

This paper summarizes the development of a methodology for the restimulation candidate selection in tight gas sands. The methodology incorporates virtual intelligence techniques (artificial neural networks, genetic algorithms and fuzzy logic) to achieve this objective. Artificial neural networks are used to develop a representative model of the completion and hydraulic fracturing process in a specific field. Genetic algorithms are used as a search and optimization tool to identify the missed incremental production based on the neural network model. Finally fuzzy logic is used to capture the unique field experiences of the engineers as well as detrimental parameters (if such parameters are indeed present) and incorporate them in the decision making process. Approximate reasoning approach is used at the decision making level to identify the restimulation candidates. Once the methodology is introduced, it is applied to an actual tight sand field in the Rocky Mountain region and the results are presented.
Practical Technique to Identify Infill Potential in Low-Permeability Gas Reservoirs Applied to the Milk River Formation in Canada
Authors: Hudson J. W. , Jochen J. E. , Jochen V. A.
Published: December 2007

This paper describes the application of a practical technique to determine infill potential when faced with little time, large data sets, and complex geology. Using this technique, we determined where newer wells are encountering potentially depleted reservoir and the infill potential for the Milk River formation within a 900-well, 200,000-acre area in the Western Canada Sedimentary Basin. We obtained these results in a minimal amount of time and used only monthly production and wellbore location data. We validated our technique by "history matching" the production performance of recently drilled wells. We correlated well quality with historical well densities in order to predict the infill well potential from 160-acre spacing to an 80-acre well spacing. We estimated ultimate recoveries for all existing wells and infill candidates and show their reserve distributions. We identified 896 infill candidates with 8.9 × 109 m3 of gas reserves. The results of this study are presented in this paper using tables, graphs, and maps.

The results of a study applying this analysis technique can be used when budgeting and planning near-and long-term drilling programs. The analysis techniques described in this paper could be applied by operators in other areas and reservoirs to evaluate their own acreage position or infill drilling potential.
New Approach for Simultaneous Determination of the OGIP and Aquifer Performance with No Prior Knowledge of Aquifer Properties and Geometry
Authors: Vega L. , Wattenbarger R. A.
Published: December 2007

Traditionally, the p/z plot has been used to describe the behavior of volumetric depletion gas reservoirs. Several authors1,2,3, 4 have pointed out, though, that this technique can lead to serious misinterpretations of the drive mechanism and overestimation of the original gas in place (OGIP) if the reservoir produces under the influence of an encroaching aquifer.

Although regression analyses have been presented5,6 to obtain a more accurate aquifer description, a solution to the non-uniqueness problem still relies on a prior knowledge of the aquifer properties and geometry.

The approach proposed here makes use of aquifer influence functions. A general pattern of the normalized absolute error function allows the simultaneous determination of the OGIP of a reservoir and a description of the aquifer performance. No assumptions regarding aquifer properties or geometry need to be made.
Reserves to Production Ratios and Present Value Relationships
Authors: Hayhow I. G. , Lemee J. A.
Published: December 2007

Reserves to production ratio (R/P) is equivalent to the inverse of an exponential decline rate which is commonly used to forecast production rates. For a tank type gas reservoir, adding wells will increase the pool's producing rate and reduce the reserves life and R/P. Therefore, R/P indirectly represents the amount of development. For this analysis the optimum R/P is the value which results in the highest present value.

An approximation of present value for a single pool is represented by a single equation which takes into account the number of wells in the pool, initial productivity, capital cost per well, decline rates, discount factors and the netback received. A second equation has been derived to calculate the optimum R/P or the amount of development, which will yield the maximum present value. The results from these equations are not precisely the same as those determined by the cash flow model, but they are useful for checking sensitivities to various input parameters. The equations show that every pool has a unique maximum present value which is dependant on pool size, productivity, capital cost, number of wells, etc. However, the R/P at which the maximum present value occurs is only dependant on the ratio of individual well productivity to its capital cost (q/c). The equations also show that the optimum R/P decreases for pools with higher q/c ratios. This dependency to q/c ratios suggests that the optimum R/P for recently discovered pools will likely be lower than for older pools of equivalent reservoir quality because of improvements to the q/c ratio. New producing techniques such as horizontal wells and the utilization of an established infrastructure have increased productivity relative to the capital invested.

The optimum R/P's have been determined for a number of pools using the equations and these results have been compared to values derived from a cash flow model.
Evaluation of Fluid pH Effects on Low Permeability Sandstones
Authors: Simon D.E. , McDaniel B.W. , Coon R.M.
Published: December 2007

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

The continued success of completing commercially producing wells in formations with permeabilities in the 0.5 to 0.01 millidarcy range has resulted in the need for laboratory techniques in evaluating the effects of water base stimulation fluids on the formation matrix. Use of fluid flow tests becomes nearly impossible and results are generally inconclusive when the air permeability is less than 0.5 md. Still, the permeability is less than 0.5 md. Still, the need exists for evaluating the compatibility of potential aqueous stimulation fluids with formation minerals.

The purpose of this paper is to report on the use of the Scanning Electron Microscope (SEM) to evaluate the effect of pH of aqueous base fluids on clay minerals associated with the pore space. Included are SEM photomicrographs showing sample areas before and after exposure to aqueous fluids with emphasis being placed at the pore openings. All work is directed toward low permeability sandstone formations.

This study is concerned with the effect of pH on the relatively nonswelling clay minerals, kaolinite, chlorite, and illite, as well as the more highly water swellable clays, mixed layer and montmorillonite. By examining SEM micrographs of a small area of the core before and after exposure to fluids with different pH values, it can be seen that the formation rock samples tested are in general, more compatible with low pH fluids than with high pH fluids.

Introduction

In the past few years, the energy crisis has caused the price of natural gas to increase at an unprecedented rate. Higher prices now being paid for natural gas have greatly increased the importance of low permeability reservoirs, many of which are sandstone formations containing significant quantities of clay minerals. Presence of clays causes concern when use of a water base fluid is contemplated. Prior to this time, the only reliable testing procedure for evaluation of fluid procedure for evaluation of fluid compatibility in low permeability sandstones was the use of time consuming "Regained Gas Permeability Tests". This required specialized equipment with costly mass flow meters to accurately measure the very low gas flow rates.

This paper presents a new procedure utilizing the Scanning Electron procedure utilizing the Scanning Electron Microscope (SEM) to evaluate formation compatibility with aqueous base fluids.
Hydrodynamic Investigation of Gas-Condensate Wells Based on Hysteresis Phenomena
Authors: Panfilov M. , Kabanov N.
Published: December 2007

The theory of in-situ experiments destined to obtain the information about the relative permeability for gas-condensate mixtures is elaborated. Theoretical basis is the analytical solution of the nonlinear problem of flow towards a well obtained by the asymptotic methods of singular perturbation theory. Analysis of the solution has shown the saturation field to be sensible to some particular modes of flow rates variation in time, which comprises as increasing, as decreasing of the flow rate. Analyzing the hysteresis loop of the wellbore saturation as the function of flow rate, we define the relative permeability for liquid. The relative permeability for gas results from the measurement of the borehole pressure.
Use of the Natural Gas of Camisea Peru for Electric and Gas Systems in the North of Brazil
Authors: Carrera Guido Z. , dos Santos Edmilson M.
Published: December 2007

The Amazon region has been demonstrating a great oil and gas potential in Brazil and in the neighboring countries, specially the field of Camisea in Peru. However, the development of feasible and economically justifiable transport systems, that can allow the flow of those resources to their potential markets, continues to be the great challenge. In this work, we present one option that can be transformed into competitive and commercial project. We describe a gas pipeline option, discussing about their technical, economic and commercial aspects. We suggest that the fields already discovered in the area should be treated in an integrated way, achieving larger economies of scale in more ambitious initiatives aiming at exports.
The Development and Application of an Accurate Assay Technique for Sulphonated Polyacrylate Co-polymer Oilfield Scale Inhibitors
Authors: Chilcott N. P. , Phillips D. A. , Sanders M. G. , Collins I. R. , Gyani A.
Published: December 2007

Chemical inhibitors that prevent the formation of sulphate and carbonate mineral scale formation are used in field squeeze treatments. The demand for competent evaluation of all issues associated with mineral scaling in wells and pipelines is continuous throughout the lifetime of any producing asset and the cost implications are very large. It is therefore important that the chemical inhibitor species can be accurately assayed so that the end of the squeeze lifetime can be determined.

Previous work by others has reported the development of accurate detection and assay techniques for oilfield scale inhibitors1,2. For PVS and VS-Co type inhibitors, these methods involve pre-treatment/purification stages that allow the application of standard wet chemical techniques, in particular the separation of the inhibitor chemical from interfering brine salts. However the typical size of samples from experimental core floods are so small that they render these methods impractical.

In this paper we detail the development of a turbidimetric method without the need for pre-treatment/purification stages for the determination of a sulphonated-polyacrylate co-polymer using Hyamine 1622. The applicability of this technique is illustrated with coreflood samples having small volume size and with real field post-scale inhibitor squeeze produced water samples. It is also shown that the method developed allows the determination of scale inhibitors in produced waters with up to 55,000ppm total chloride concentration and 100ppm crude oil in water.

Finally we report the potential interferences caused by the inhibitor carrier, crude oil and displacement fluid which may arise as a result of both typical and atypical squeeze treatments.
Increasing Squeeze Life on Miller with New Inhibitor Chemistry
Authors: Bourne H M , Williams G , Hughes C T
Published: December 2007

The water chemistry prevailing in the BP Amoco operated Miller field presents one of the harshest scaling environments in the North Sea. The high barium, moderate salinity brine, coupled to a relatively high bottom hole temperature produces a scaling environment that dictates the need for high concentrations of exotic scale inhibitor chemistry for downhole scale control. These high levels of inhibitor, typically 10-200 ppm, are particularly difficult to sustain over long production periods. This leads to a relatively short squeeze life and thus high well intervention frequency and deferred oil costs.

Vinyl sulphonate chemistry has been shown to be particularly effective at controlling scale deposition under Miller conditions. However, its retention characteristics are less than ideal, leading to short treatment life. A new chemistry has now been developed which realises the benefits of the vinyl sulphonate functionality whilst achieving significantly higher retention and thus the potential for longer treatment life. This has been achieved by incorporating a novel phosphorus containing species into the polymer matrix.

Laboratory studies suggest that the new inhibitor combines significantly improved performance with superior environmental properties. One field trial has already been completed and another is currently ongoing. The trials have already achieved a significant increase in squeeze life.

Results to-date indicate that operating costs can be significantly reduced through development of a novel chemistry designed to meet the specific needs of a particularly harsh scaling environment.
Interpretation of Bottom-Hole Pressure Build-up Tests on Fractured Oil Reservoirs
Authors: El-Hadidi Samir M. , Ritter A.E.
Published: December 2007

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

This paper is designed to develop a procedure to analyze pressure buildup curves procedure to analyze pressure buildup curves where radial flow theory does not apply.

In a vertically fractured system, which is present in most West Texas carbonate reservoirs, present in most West Texas carbonate reservoirs, flow in the region nearest the fracture is essentially linear, whereas, further out in the formation, radial flow normally prevails. Historically, interwell flow capacity, fracture length, wellbore damage and static pressure have been determined using the late time slope from pressure log time curves. This solution is pressure log time curves. This solution is based on a radial flow model and, as a result, most of the computed reservoir parameters are in error.

A set of guidelines are established to allow uniform interpretation of pressure buildup curves and to determine the best workover candidates for fractured oil reservoirs. Field examples representing four basic cases are also presented. presented

Introduction

The presence of natural or induced fractures will influence the flow behavior in oil reservoirs. In a fractured system, flow in the region nearest the fracture is practically linear, whereas farther away from the fracture, essentially radial flow prevails. Thus, transient pressure analyses based on radial flow theory are incorrect when applied to reservoirs where linear flow predominates.

In the past few years, the slope and position of the straight-line portion from position of the straight-line portion from transient pressure vs the logarithm of shut-in time plot has been used exclusively to determine the flow capacity, condition ratio and static pressure for oil wells with natural or induced pressure for oil wells with natural or induced fractures. In most cases, the straight lines used have not been the proper ones. A stable pressure gradient was never reached in these pressure gradient was never reached in these cases; however, equations based on conventional radial flow theory were used. This resulted in the improper calculation of a condition ratio greater than one, of higher than actual interwell flow capacity, and of an improved wellbore condition where, in actuality, wellbore damage might exist.

The calculation procedure presented in this paper enables the user to detect the conditions paper enables the user to detect the conditions around the wellbore and aids in determining whether the well is a good candidate for workover.