bluuebunny/crossref_metadata_2025 huggingface dataset:
Gas Shutoff Evaluation and Implementation, North Slope, Alaska
Authors: Hupp D. , Frankenburg A. , Bartel P. , Roberts G.
Published: December 2007

Oil production on Alaska's North Slope has been limited as a result of gas production and the ensuing gas handling-facility constraints. Diagnosis of gas production problems is complicated by the fact that many of the wells are high-angle or horizontal. This paper presents case studies in the diagnosis and treatment of excess gas production in three horizontal oil wells located on the North Slope of Alaska.

Candidate wells for gas shutoff (GSO) were identified based on gas flow rates and the gas/oil ratio (GOR). Wells that were not commercially producible were selected for evaluation as potential GSO wells. These wells were assessed with new-technology logging tools conveyed on coiled tubing or with a downhole tractor. The new production-logging technology provided direct gas and oil holdup measurements, allowing for interpretation of three-phase production in the horizontal well environments. The goal was to identify dry-gas production (i.e., gas production without associated oil production).

After dry-gas production was identified, GSO procedures were designed based on the location of the gas entry into the wellbore. Two of the case studies involved GSO from the toe of the horizontal section of the wells, which was accomplished by placing a cast-iron bridge plug on coiled tubing above the gas-producing perforations. The third case study identified dry-gas production from the top perforated interval. This GSO involved setting a plug below the gas-producing perforations and squeezing them off. The plug was then drilled out with coiled tubing and pushed to total depth (TD).

These techniques proved to be economical GSO solutions in difficult well environments, and each case resulted in significant reduction of free gas and increased oil production.
Design and Analysis of a Multiphase Turbine for Compact Gas-Liquid Separation
Authors: Rawlins C. H. , Ross G. D.
Published: December 2007

The rotary separator turbine (RST) uses unique technology to provide compact separation of oil and gas while recovering energy wasted in conventional pressure-reduction operations. The technology has been used for industrial refrigeration and geothermal applications since the early 1980s and has recently finished a field evaluation and assessment on a deepwater, tension-leg platform (TLP) in the Gulf of Mexico. The focus of this paper is to cover the operating principles and mechanisms of multiphase turbine technology and the design parameters for installation as a separation or power-generation system in new developments or in debottlenecking applications. Operational experience pertaining to separation efficiency, mechanical reliability, and power output in a live-fluid environment are highlighted.
Porosity Prediction in Shallow vs. Deepwater Limestones
Authors: Scholle Peter A.
Published: December 2007

Limestones can be divided arbitrarily into shallow- and deepwater types. Shallow-water limestones characteristically have complex depositional facies patterns and originally are composed primarily of unstable minerals (aragonite and high-Mg calcite), which make them highly susceptible to post-depositional alteration. Small differences in burial-uplift-water chemistry histories can produce radically different trends of porosity preservation, destruction, or creation as a consequence of the great susceptibility of unstable minerals to alteration by fresh (nonmarine) pore fluids. These factors make porosity prediction of shallow-water limestones very difficult. Only through careful and detailed mapping of both primary facies and mineralogical trends, coupled with equally painstaking determinations of diagenetic histories and patterns, can porosity predictions be made for shallow-water limestones.

Deepwater, pelagic limestones, on the other hand, commonly are composed of a much more stable primary mineral (low-Mg calcite) and have more uniform and predictable facies patterns. Studies performed on Mesozoic and Cenozoic chalks throughout the U.S. and Europe have shown that porosity is lost as a direct function of burial depth. The rates of porosity loss vary with the pore-water chemistry and, more importantly, as a function of pore-fluid pressure. If these factors are known with reasonable certainty, then reasonable predictions can be made of average subsurface porosity of deepwater limestones. Only where such limestones have never been buried deeply, where they have had an early input of oil, or where they have elevated pore-fluid pressure can high porosities and high petroleum-reservoir potential be expected.

Scanning electron microscopy (SEM), petrography, and isotopic analysis have proved useful techniques for deciphering the depositional and diagenetic histories of both shallow- and deepwater limestones.

Introduction

Prediction of porosity in carbonate rocks is at best a difficult undertaking. Most carbonate hydrocarbon reservoirs drilled to date have been in shallow-water limestones. In such rocks, depositional patterns are complex and variable and diagenetic alteration of original sediment textures and compositions may be extreme. Few, if any, general rules can be used to predict the porosity of such carbonate rocks in the absence of drilling data. Even where a significant number of wells have been drilled, useful porosity trends that enable accurate porosity prognostication over even relatively short distances may be difficult to discern.

Porosity prediction in deepwater limestones, on the other hand, generally is easier. Deepwater strata have more uniform depositional facies, more predictable primary chemical compositions, and simpler diagenetic alteration patterns than their shallow-water equivalents. Alteration of deepwater limestones is controlled mainly by their maximum burial depth. Average rates for such diagenetic porosity loss can be determined as a function of burial.
A Parallel Reservoir Simulator for Large-Scale Reservoir Simulation
Authors: Dogru A. H. , Sunaidi H. A. , Fung L. S. , Habiballah W. A. , Al-Zamel N. , Li K. G.
Published: December 2007

A new parallel, black-oil-production reservoir simulator (Powers**) has been developed and fully integrated into the pre- and post-processing graphical environment. Its primary use is to simulate the giant oil and gas reservoirs of the Middle East using millions of cells. The new simulator has been created for parallelism and scalability, with the aim of making megacell simulation a day-to-day reservoir-management tool. Upon its completion, the parallel simulator was validated against published benchmark problems and other industrial simulators. Several giant oil-reservoir studies have been conducted with million-cell descriptions. This paper presents the model formulation, parallel linear solver, parallel locally refined grids, and parallel well management. The benefits of using megacell simulation models are illustrated by a real field example used to confirm bypassed oil zones and obtain a history match in a short time period. With the new technology, preprocessing, construction, running, and postprocessing of megacell models is finally practical. A typical history-match run for a field with 30 to 50 years of production takes only a few hours.
Improved Micellar/Polymer Flooding With High-pH Chemicals
Authors: Holm L.W. , Robertson Steven D.
Published: December 2007

A study was made of various pre flush solutions for use in micellar/polymer flooding. The oil recovery in laboratory core floods was improved most by the use of high-pH silicate solution as a preflush and by adding chelating agents such as sodium NTA or sodium EDTA to the micellar slug.

Introduction.

One of the techniques which has great promise for recovering large quantities of residual, oil is micellar/polymer flooding.1–3 In this type of process, surfactants (micellar solutions) and polymers are used to recover oil left behind by waterflooding and other secondary recovery methods. Laboratory and field tests of micellar/polymer flooding processes have been conducted in the U.S., with a number of projects currently in progress.4 During this period, the reservoir' variables that affect the efficiency of the process have been more clearly identified and studied. The principal variables, which are also the most detrimental to the oil recovery efficiency of the processes, are (1) reservoir rock heterogeneity, (2) reservoir brine salinity, (3) clays arid other minerals present in the reservoir rock, and (4) multivalent cations present on the reservoir rock surfaces.

Further studies have continued on how these variables affect the processes and on techniques for modifying deleterious factors and improving process efficiency. A process which uses chemicals (surfact ants and polymers) which are not affected adversely by these variables may seem to be the ideal goal; however, recognition of all the complex variables involved in micellar processes and the costs of chemicals required for such a process leads to the conclusion that this goal may not be a practical one.

Since the early field tests of micellar flooding, changing and conditioning the reservoir environment has been a continuing goal. Pre flushing cores in the laboratory and the reservoir rock in field test areas with fluids that would replace or change the existing water or brine were used m many projects.5–7 Reducing flow in permeable channels, replacing high-salinity brines with fresher water, and injecting sacrificially absorbed agents ahead of the micellar fluids were the objectives of the injection of various preflush solutions. None of the attempts were completely satisfactory. At the same time, other research efforts8,9 were directed toward addition of chemicals to the micellar slug which would increase the tolerance of the surfactants to reservoir brine and/or multivalent cations and improve phase relationships of the micellar slug with the reservoir fluids.
Basic Fluid and Pressure Forces on Oilwell Tubulars
Authors: Hammerlindl D.J.
Published: December 2007

The object of this paper is to clearly and simply define the basic fluid and pressure forces on oilwell tubulars with respect to stresses, buoyancy, neutral point, and the effective buckling force denoted as the "fictitious force." The paper is designed as a preface to Lubinski and Hammerlindl.

Introduction

Conventional thought seems to be that an understanding of the basic fluid and pressure forces in oilwell tubulars is the domain of experts only. The objective of this paper is to disprove this by presenting a simple explanation of these basic forces. presenting a simple explanation of these basic forces. Part of the misunderstanding results from the belief that the problem is complex and difficult, when actually only an elementary knowledge of pressure and stress is required. In purely mechanical pressure and stress is required. In purely mechanical systems (i.e., no fluid or pressure), most engineers readily can determine and understand the forces associated with Hooke's law and buckling. However, with the addition of fluids, the engineer may become confused as to (1) whether buoyancy is a concentrated or distributed force, (2) why the neutral point is not at the point of zero axial stress, and (3) point is not at the point of zero axial stress, and (3) the nature of the nebulous force denoted as the "fictitious force" by Lubinski and Blenkarn. All of the above can be understood easily by observing the distribution of the principal stresses. This paper interrelates these stresses with buoyancy, the neutral point, and the fictitious force. point, and the fictitious force. The objectives of this paper are to give the practicing engineer a working knowledge of basic practicing engineer a working knowledge of basic fluid and pressure effects on oilwell tubulars and to increase the industry's ability to understand and advance the existing literature.

Stress Distribution in the Absence of Fluid

Fig. 1a illustrates a freely suspended tube of constant inside and outside diameter. In the absence of fluid, the axial stress at any point is equal to the weight below that point divided by the cross-sectional area of the tube at that point. Thus, the axial stress at a point a distance x from the lower end may be point a distance x from the lower end may be determined from

(1)

Fig. 1b shows the axial stress distribution in the absence of fluid, over the entire length.Throughout this paper, compressive forces are considered to be positive and tensile forces are considered to be negative, accounting for the minus sign in Eq. 1 and the equations that follow. Also, all equations pertain to a system of constant units.The radial stress at any point is obtained from

(1)

where p and p are the internal and external pressures, respectively, at the point of interest. pressures, respectively, at the point of interest. JPT

P. 153
Application of Vector Processors To Solve Finite Difference Equations
Authors: Nolen James S. , Kuba D. W. , Kascic M. J.
Published: December 2007

As computer technology approaches limitations imposed by the speed of light, increased emphasis is placed on vector processors. These have the ability to increase greatly the speed of arithmetic even without improvements in such basic computer characteristics as memory cycle time. This paper deals with solving systems of finite difference equations on the STAR 100 and the CYBER 203, two Control Data Corp. computers with built-in vector processors.

Systems of three-dimensional finite difference equations having from 2,000 to 8,000 unknowns were solved by means of Gaussian elimination and line successive overrelaxation (LSOR). On these machines, the D4 Gaussian elimination technique reduced computer time by factors as large as 4.6 relative to standard Gaussian elimination. Vectorization of the D4 code on the STAR 100 reduced computer times relative to scalar results by factors as large as 26, despite nonoptimal coding.

LSOR was vectorized successfully with computer time reduction factors of 35 to 43 on the STAR 100. On the CYBER 203, run times were reduced by factors of 45 to 54, relative to the scalar performance of the STAR 100. On an 8,000-block problem, average processing speed for a complete LSOR solution was approximately 25 million floating operations per second (megaflops).
Evolution of Japanese Energy Policy
Authors: Matsuzawa Akira , Tsumura Akinobu
Published: December 2007

To limit oil imports, Japan has established goals for 1985 and 1990 in terms of energy conservation, production of nuclear power plants, importation of LNG and coal, and development of new energy sources. In addition, the government and private concerns are making efforts for strengthening the exploration and development of oil resources and for diversifying the sources of imported oil.

Introduction

Two decades before the oil crisis in 1973, Japan had enjoyed unprecedented rapid growth of its economy. The gross national product (GNP) had increased 10% per year in 20 years, resulting in a rapid growth of energy consumption. Total energy consumption in 1973 was equivalent to 7 MMB/D (407 × 106 m3/a) compared with 1 MMB/D (58 × 106 m3/a) in 1953. Oil consumption represented 87% of this increase. As a result, in 1973 Japan was consuming 5.5 MMB/D (319 × 106 m3/a) of oil, which represented 75% of primary energy consumption, and 99.8% of the oil was imported. In fact, Japan's rapid economic growth for two decades had relied on the plentiful and stable supplies of oil that had been achieved in the world, particularly in the Middle East.This crisis, first experienced as oil shortages and sharp price increases, had an especially profound impact on oil-dependent Japan. Trends in economic growth changed fundamentally after the oil shock and the unprecedented recession that followed. In the postcrisis period, there has been little expectation that the future economic growth rate will equal that of the pre-1973 period.As a result of observations over the past few years on the global development of oil and other energy sources, and through continued discussions concerning the future status of these sources, the great majority of Japanese have become aware that a stable energy supply will be the decisive factor for economic growth in the future.

Guidelines of the Ministerial Task Force for Energy Policy

The oil shock made the Japanese government and people aware of the importance of stable supplies of energy for future economic performance. The government set up the Natural Resources and Energy Agency (attached to the Ministry of International Trade and Industry) and the Ministerial Task Force for Energy Policy, headed by the prime minister.In 1975, upon request by the Natural Resources and Energy Agency, the Advisory Committee for Energy worked out a recommendation for a new energy policy, including interim projections of energy supply and demand. The Ministerial Task Force reviewed the report submitted by the committee and set up guidelines for an energy policy.The result of the study by the committee suggested that there is no simple and easy way to ensure a stable energy supply for a country like Japan, which lacks the indigenous energy resources and is dependent on large amounts of energy.

JPT

P. 1691＾
Mixing Rules and Correlations of NMR Relaxation Time With Viscosity, Diffusivity, and Gas/Oil Ratio of Methane/Hydrocarbon Mixtures
Authors: Lo Sho-Wei , Hirasaki George J. , House Waylon V. , Kobayashi Riki
Published: December 2007

Viscosity, diffusivity, relaxation time, and gas/oil ratio are important properties in the characterization of reservoirs by nuclear magnetic resonance (NMR) well logging and in prediction of production performance. For the past few years, NMR well logging has been used to estimate formation properties and hydrocarbon liquid/ vapor characterization. Previous work has shown that pure al-kanes, alkane mixtures, viscosity standards, and stock tank crude oils have NMR relaxation times that vary linearly with viscosity/ temperature and diffusivity on a log-log scale. However, pure methane at some temperatures and pressures does not follow the same trend. Thus, the linear correlation may not be valid for live crude oils that contain a significant amount of methane. Therefore, the study of methane-hydrocarbon mixtures is of interest.

An NMR spectrometer equipped with a high-pressure probe was used to study the relationship between NMR T1 relaxation time and viscosity/temperature, diffusivity, and gas/oil ratio of methane-hydrocarbon mixtures. Relaxation time and diffusivity measurements of three mixtures were made: methane-n-hexane, methane-n-decane, and methane-n-hexadecane. It was found that unlike stock tank oil, relaxation times do not depend linearly on viscosity/temperature on a log-log scale. Each of the mixtures forms a different curve.

Generalized correlations between viscosity, diffusivity, gas/oil ratio, and NMR relaxation times were developed. First, the relaxation time mixing rule was developed by studying the theory of NMR relaxation mechanism. From the mixing rule, it was found that departure of relaxation times of methane-n-alkane mixtures from linear correlations on a log-log scale can be correlated with the proton fraction of methane, expressed as gas/oil ratio. Thus, correlations between relaxation time, viscosity/temperature, and gas/oil ratio were developed. Correlations between relaxation time, diffusivity, and gas/oil ratio were also developed. There is a linear relation between diffusivity and viscosity/temperature that is independent of composition. From these correlations, viscosity and gas/oil ratio can be estimated from NMR T1 relaxation time and diffusivity.
The Role of Sequential Well Testing in Improving Oil Recovery From a Closed Sand Lens in the Bahrain Field
Authors: Zubari H.K. , Abdulwahab A.E.
Published: December 2007

The Ac zone refers to the sandstone facies of the Wara formation, which belongs to the Wasia group of the Middle Cretaceous age.* Owing to variable shale to sand ratios, the Ac zone is realized as different isolated sand lenses scattered all over the field. Owing to the complexity of the geology and the flow mechanism, well testing was used to manage the reservoir. The concept of a sequence of well tests on the same well was found to be essential in improving the oil recovery. Conducted on a specific well situated within a closed sand lens, sequential well testing yielded valuable information that assisted in understanding the drive mechanism and the deteriorating reservoir parameters, permeability, and skin. Such a method was crucial in improving the recovery from the sand lens as well as from the single-well-treatment perspective. This paper presents an example of how such a technique aided in improving the oil recovery from a small sand lens.
Relative Permeability Correlation for Mixed-Wet Reservoirs
Authors: Kjosavik A. , Ringen J. K. , Skjaeveland S. M.
Published: December 2007

A two-phase relative permeability correlation for mixed-wet rock is presented and validated. It includes provisions for bounding drainage and imbibition processes and scanning hysteresis loops, and is inferred from a capillary pressure correlation.

The well-known Corey-Burdine relative permeabilities were developed for water-wet rock from a Brooks-Corey power-law capillary pressure correlation and a bundle-of-tubes network model. We have extended this correlation to mixed-wet rock and now propose the ensuing relative permeability correlation for mixed-wet reservoirs. The functional form is symmetric with respect to fluid-dependent properties, because neither fluid has precedence in a mixed-wet environment. It reverts to the standard Corey-Burdine correlation for the completely water- or oil-wet cases, and exhibits the following characteristics in agreement with reported experiments: first, water-wet behavior at low water saturations and oil-wet behavior at low oil saturations; second, an inverted S-shape oil relative permeability curve with an inflection point; and, third, closed hysteresis scanning loops.
Alternate Producing and Gas Repressuring for Greater Oil Recovery
Authors: Cook Alton B.
Published: December 2007

Considerations are presented to support a theory that alternately producing and repressuring a reservoir with gas will flush oil out of zones of low permeability in a reservoir under conditions in which conventional gas cycling would be relatively ineffective.

Gas repressuring and batch gas cycling (alternately producing and repressuring) in semidepleted oil reservoirs may be a practical secondary recovery practice in many fields. Although this practice may not be as successful as water flooding in most shallow oil reservoirs, it holds considerable promise as a means of increasing recovery from deep reservoirs where water flooding would not be economically practicable.

Batch-type gas cycling will sweep a greater part of a non-homogeneous reservoir than conventional gas cycling and therefore should result in a greater oil recovery. It can be used successfully where two or more reservoirs can be operated as a unit. Also, it can be used in a single reservoir if the reservoir is also used for gas-storage operations. This cycling procedure can be used successfully in reservoirs whose states of depletion range from newly developed oil fields to fields depleted by primary production.

Introduction

From a study of methods of predicting the performance of semidepleted oil reservoirs used for gas storage made recently by Bureau of Mines engineers, it was concluded that the amount of oil recoverable by repressuring and cycling a reservoir may be as great as that produced during primary recovery operations. It appeared also that the normal operations of a gas-storage project would generally gas-sweep a larger part of a reservoir than gas cycling at essentially constant pressure, especially in unfractured reservoirs with large variations in permeability.

The flow of fluids in a reservoir used for gas storage differs from that in reservoirs subjected to gas cycling. In normal gas-cycling operations in non-homogeneous reservoirs the reservoir pressure is essentially constant, and the major flow of gas is through the more permeable zones. When a reservoir is used for gas storage, the oil-recovery operation may be in effect an alternate repressuring and partial depletion process.
A Study of Relevant Parameters To Predict Sand Production in Gas Wells
Authors: Ghalambor Ali , Asadi Mahmoud
Published: December 2007

A sensitivity analysis was carried out during a course of study to develop a model for predicting sand production from Gulf Coast gas wells that produce free water. A multiple linear-regression analysis was used to incorporate data from producing gas wells and log-derived properties of reservoir rock in a useable model. This model fits the field data of water-producing gas wells. It will be a risky proposition to analyze each individual parameter related to sand production when designing sand-control measures. This study shows that the combined effects of these parameters are making a significant contribution in the process. The results indicate that the volume of water is not relatable, but the presence of free water (uncondensed from the gas phase) increases the sanding tendencies of most gas wells. As a reservoir depletes, its tendency to produce sand increases; efforts to reduce sanding should be directed toward reducing the drawdown across the completion; and many of the log-derived parameters that show merit in correlating the sanding tendencies of dry gas wells have no value in waterproducing gas wells.
Quantitative Risk Assessment as a Design Tool—Recent FPSO Experience
Authors: Overfield R. E. , Collins J. F.
Published: December 2007

Quantitative risk assessment was used as a tool for the conceptual and detailed design of two floating production, storage, and off-loading (FPSO) installations. Results from the risk-assessment study were used to identify significant risk contributors that influence the design and operation of the facilities and to demonstrate that the risk-acceptance criteria adopted by the company were met. The results were also used to identify opportunities to further reduce the risk to a level that is as low as reasonably practical (ALARP).

Traditional risk, reliability, and consequence analysis methods were used to evaluate impacts from process and marine facilities and to determine the design of accidental loads during the conceptual engineering and design phases. Results were used as data for a detailed fault-tree analysis of accident scenarios and used to set the design criteria for significant structures and facilities.

In addition, analyses of subsea facility interfaces and field operations were performed to incorporate the full development scope. Particular attention was given to subsea pipelines and flexible risers as well as tanker operations and their effects on FPSO operation and design.

Event frequencies were determined from industry data and conditioned for the special design and operating features of the chosen FPSO concept. Risk sources, impacting fatal accidents, impairment of safety functions, and loss of asset value, were quantified for use in demonstrating an acceptable level of risk and to test opportunities to further reduce operating risks.

Results from the analyses show that process fires and explosions dominate the risks to personnel and safety functions, followed by cargo tank explosions. Tanker collisions, subsea pipeline and riser leaks, and turret operations were found to represent significant asset risks. Design development and operations planning efforts focused on these areas to reduce risk and improve reliability.
A Numerical Method for Computing the Dynamical Behavior of Fluid-Fluid Interfaces in Permeable Media
Authors: Sheldon J.W. , Dougherty E.W.
Published: December 2007

A numerical method for computing the dynamical behavior of fluid-fluid interface is described. Results of studies made to assess the accuracy and economy of the method on a computer are reported. If is concluded that it is practical to obtain digital computer solutions for a fluid-fluid interface problems with two space dimensions.

PROBLEM DEFINITION

We consider two-dimensional flow in a rectangle as shown in Fig. 1, where a fluid-fluid interface divides the rectangle into two regions. The pressure is specified along the lower boundary (the injection boundary) and upper boundary (the withdrawal boundary). There is to be no flow of fluid across the side boundaries, which are walls of symmetry for the flow, and px = 0 along these boundaries. The fluids are incompressible, the absolute permeability and porosity is constant, and each fluid has its own constant mobility. Thus the pressure satisfies Laplace's equation in each region. Across the interface, pressure is continuous and the normal component of fluid flux is 1. These conditions are shown in Fig. 1. The velocity of a point on the interface in the direction of the normal from Fluid 1 into Fluid 2 is, where is thenormal component of volumetric flux at the point on the interface, i.e.,

For brevity, we call the problem defined above "Problem A". Problem A is a simple example of a dynamical fluid-fluid interface problem. However, the same numerical methods which we use to solve Problem A can be extended to the solution of a large number of fluid-fluid interface problems which are mathematical models for various oil recovery processes, hence our interest in Problem A.

OUTLINE OF METHOD OF SOLUTION

We define the interface by prescribing the x, y coordinates of a finite set of points. These points are called "interface meshpoints" and are illustrated by triangles or asterisks in the figures. Fig. 2 is a procedural (flow) chart displaying the main steps in the solution. We comment briefly on some of these steps in this section and then give further details in subsequent sections.

SPEJ

P. 158ˆ
Laboratory Results of Cleaning Produced Water by Gas Flotation
Authors: Strickland W. T.
Published: December 2007

Laboratory studies were conducted to determine the factors governing flotation-cell performance. It was learned that oil removal is increased by increasing collision and attachment efficiencies and gas/liquid contact time. Collision efficiency is increased by increasing oil-drop size and gas concentration and by decreasing gas-bubble size. Several factors (crude type, pH, temperature, etc.) were found to change attachment efficiency. No correlation between basic system properties and attachment efficiency was found.

Some of these important parameters are determined by the cell design, whereas others are characteristics of the feed. Thus, the same type (design) cell will produce different effluent oil concentrations for different feeds. Also, the effluent from a given cell will change when the feed characteristics change.
Thermal Simulation With Multisegment Wells
Authors: Stone T. W. , Bennett J. , Law D. H. -S. , Holmes J. A.
Published: December 2007

The extension of a previously reported well model to compositional and thermal applications is discussed. This multisegment, multibranching wellbore model has been fully coupled to a commercial reservoir simulator that can operate in black-oil, compositional, or thermal modes. In this paper, the discussion will focus on thermal, heavy-oil applications in which simulation requires a better representation of the wellbore geometry and the physics of fluid flow and heat transfer.
Fracture Pressure-Slope Analysis for TSOs in High-Permeability Formations
Authors: Smith Jeffrey E. , Meyer Bruce R. , Jacot R. Henry
Published: December 2007

The relative popularity and success of the frac-pack technique in hydraulic fracturing has resulted in some misconceptions regarding the objective, procedure, and pressure analysis after a screenout. This paper addresses frac-pack procedures and the pressure response after a tip screenout (TSO).

An analytical method has been developed for analyzing pressure-slope behavior after a TSO in high-permeability formations. These equations incorporate the first order parameters affecting the fracture pressure, rate of pressure change (derivative), and pressure-slope behaviors after a screenout.

The fundamental equations for pressure-slope analysis are similar to those originally developed by Nolte for pressure-decline analysis. The major difference is that after the fracture stops propagating (i.e., after a TSO), the injection rate is not zero. Consequently, if the injection rate is greater than the leakoff rate, the fracture volume and net pressure (constant compliance) must increase. If the injection rate falls below the leakoff rate, the fracture net pressure must decrease.

Although analytical equations will not replace 3D fracturing simulators normally used for design and real-time history matching, they do provide insight into the major parameters affecting pressure behavior after a TSO without running a numerical simulator. The analytical equations presented in this paper demonstrate why pressure slopes after a screenout are typically much greater than unity for low-efficiency fractures.

A generalized set of equations is presented for analyzing the pressure-slope behavior after a screenout. Numerous graphs are provided that illustrate the parametric effects of fracture efficiency, spurt loss, and fracture net pressure at the time of a screenout on the pressure, derivative, and slope behaviors after a TSO. Comparisons of the analytical pressure-slope equations with a 3D fracturing simulator are presented to show the analysis’ application.

A new methodology of frac-pack post-analysis is presented using the pressure slope technique. This methodology uses the pressure slope during a screenout as a check on the minifracture and fracture efficiency. Two frac-pack cases with bottomhole data are analyzed with a 3D hydraulic fracturing simulator to illustrate the pressure-slope analysis for low efficiency fractures.
Relationships Between the Mud Resistivity, Mud Filtrate Resistivity, and the Mud Cake Resistivity of Oil Emulsion Mud Systems
Authors: Lamont Norman
Published: December 2007

Introduction

The evaluation of certain reservoir properties, such as porosity and fluid saturation, from electrical well surveys has been widely accepted in petroleum engineering. Various investigators have established relationships between these properties and certain parameters which affect the response of the electrical log. Among these are the resistivities of the mud, its filtrate, and its filter cake. In 1949, Patnode established a relationship between the resistivities of the mud and filtrate. The well logging service companies have contributed relationships for the mud-mud cake resistivities. These have been valuable since it was the practice to measure only resistivity of mud at the well site.

During the mid–1940's the industry began drilling wells with oil-emulsion drilling fluids. These were conventional aqueous muds with a dispersed oil phase. Since 1950, oil-emulsion muds have been used on an increasing number of wells each year. However, the practice of measuring only the resistivity of the mud at the well site has continued, and the mud filtrate and mud cake resistivities have been determined by the above-mentioned relationships. Service companies are now equipped to measure all three resistivities at the well site.

An investigation was conducted on the resistivities of oil-emulsion muds, mud filtrates, and mud cakes to determine if these values conformed to the relationships for aqueous muds.

Types of Muds

Fifty-one oil-emulsion mud samples were prepared in the laboratory following a standard manual published by a leading mud company. The diesel oil in the samples varied from 5 to 50 per cent, the majority of the samples being in the 10 per cent region. The basic aqueous mud types which were converted to oil-emulsion muds were commercial clay and bentonite muds, low pH and high pH, caustic-quebracho treated muds, and lime treated muds. The emulsions were stabilized by dispersed solids, lignins, lignosulfonates, sodium carboxymethyl cellulose, or sulfonated petrolatum. It is worthy of note that after a quiescent period of two weeks at room temperature all samples, regardless of emulsifying agent, remained stable.

The make-up water for the muds was from the laboratory tap. Resistivities were varied by the addition of table salt to the water. A range of mud resistivities from 0.44 to 3.9 ohm-m was obtained in this way.
On Near-Wellbore Modeling and Real-Time Reservoir Management
Authors: Bøe Ø. , Flynn J. , Reiso E.
Published: December 2007

This paper is concerned with the problems of real-time reservoir management, simulation while drilling (SIWD), and near-wellbore modeling. These problems are discussed in terms of work process, feasibility, and numerical- and simulation-related aspects. A software tool developed to perform high-precision local simulation while accounting for global field behavior is described. Field examples are presented to illustrate the potential and use for SIWD exercises.
Development and Testing of Insulated Drillpipe
Authors: Finger J. T. , Jacobson R. D. , Champness A. T.
Published: December 2007

The Geothermal Research Dept. at Sandia Natl. Laboratories, in collaboration with Drill Cool Systems Inc., has worked to develop and test insulated drillpipe (IDP). IDP will allow much cooler drilling fluid to reach the bottom of the hole, making possible the use of downhole motors, electronics, and steering tools that are now useless in high-temperature formations. Other advantages of cooler fluid include reduced degradation of drilling fluid, longer bit life, and reduced corrosion rates.

This article describes the theoretical background, laboratory testing, and field testing of IDP, including structural and thermal laboratory testing procedures and results. We also give results for a field test in a geothermal well in which circulating temperatures in IDP are compared with those in conventional drillpipe (CDP) at different flow rates. A brief description of the software used to model wellbore temperature and to calculate sensitivity in IDP design differences is included, along with a comparison of calculated and measured wellbore temperatures in the field test. There is also analysis of mixed (IDP and CDP) drillstrings and discussion of where IDP should be placed in a mixed string.
Drillstring Considerations for Gulf of Mexico's Deepest Well
Authors: Prater Terry E. , Everage S. DeWayne , Greenip John F. , Adams Burt A.
Published: December 2007

This paper chronicles the design analysis performed to drill the Gulf of Mexico's deepest well. With small-diameter casing cemented in the hole, slimhole drilling plans for the record depth well were generated. The short fuse project required an atypical slimhole drillstring design to select a string with ample tension/ torsion capacity, sufficient flow area for hole cleaning, and immediate availability. The final design was used in an "edge of the envelope" environment with remarkable success. This paper discusses the factors involved in drillstring selection and acceptance, actual field data, post-well results, and future applications.
Optimal Control Strategy and Experimental Investigation of Gas/Liquid Compact Separators
Authors: Wang S. , Mohan R. , Shoham O. , Marrelli J. D. , Kouba G. E.
Published: December 2007

The deployment of the new technology of gas/liquid compact separators such as the Gas/Liquid Cylindrical Cyclone (GLCC, copyright, U. of Tulsa, 1994) often requires dedicated control systems for field applications. The control strategy implementation is crucial for process optimization and adaptation, especially when GLCCs are operated at a wide range of liquid and gas flow rates. In this study, a unique and simple control strategy, which is capable of optimizing the operating pressure and adapting to liquid and gas inflow fluctuations, has been developed. Detailed simulations and experimental investigations also have been conducted to evaluate the performance of the proposed control systems. The significant advantages of this strategy are threefold: the system can be operated at optimum separator back pressure, the system can adapt to the changes of liquid and gas flow rates, and the strategy can be easily implemented using simple PID controllers available on the market. This provides the oil and gas industry with a simple, robust compact separator control technique that has the potential for offshore and subsea applications.
Frac-Pack Completion of Gas-Storage Wells for Enhanced Deliverability
Authors: Peebles Bill , Kelley Robert , Ritter Wes , Fitzpatrick Harvey
Published: December 2007

This case-history paper presents the results of installing frac-pack [one-step tip screenout (TSO)1 fracture stimulation and gravelpack operations]2–5 completions in gas-storage wells in the West Clear Lake field of Harris County, Texas. With the frac-pack technique, operators have fracture-stimulated six wells (new drills and workovers) in the past 3 years as part of an overall facility upgrade. Gas is injected daily into the Frio formation (5,500 ft) of the field and withdrawn at high rates during peak demand periods. A strong waterdrive can "water-out" production at the end of peak-season gas withdrawal. The water recedes when withdrawal is ended and injection restores gas volume and pressure in the reservoir. The paper presents frac-pack installation techniques, performance comparison of conventional methods and frac packs, and completion-technique selection to achieve high production efficiency.

New wells that were completed with frac packs in 1994 have yielded rates up to 100 MMcf/D each with approximately 500 psi drawdown pressure. In 1995, a well capable of producing at 25 MMcf/D with a gravel pack was recompleted with a frac pack, which increased its rate capacity to 49 MMcf/D. Because of the performance of the first three wells, three more wells were completed with frac packs in 1997. The frac-pack completion has proven superior to other sand-control methods in providing highrate deliverability in the West Clear Lake field. Frac-pack completions have, in general, provided a two-fold increase in the daily production rate.

Frac-pack completions and recompletions can be applied in gas-storage wells where high production rates and sand-control measures are necessary for the life of the well.

This paper provides guidelines and results associated with frac packing by

Demonstrating the importance of selecting completion techniques that will provide high-efficiency production from gasstorage wells. Presenting case histories of frac-pack-stimulated gas-storagewell performance over a relatively long time period. Comparing well performance of conventionally completedand frac-pack-completed gas-storage wells producing at high rates. Providing insight into the operational aspects of frac-pack completions.
Rapid History Matching Using a Generalized Travel-Time Inversion Method
Authors: Wu Zhan , Datta-Gupta Akhil
Published: December 2007

We propose a generalized travel-time inversion method for production data integration into reservoir models using finite-difference-based reservoir simulators. Our approach is motivated by seismic waveform imaging and is particularly well-suited for large-scale field applications because the computation cost depends only on the number of wells regardless of the number of parameters or the amount of observed data. Instead of matching the production data directly, we minimize a "travel-time shift" at each well derived by maximizing the cross-correlation between the observed and calculated production response. An optimal control method is used to compute the sensitivity of the travel time with respect to reservoir parameters. Finally, data integration is carried out via a modified Gauss-Newton method.

There are several advantages associated with the proposed travel-time inversion method. First, it is robust and computationally efficient. The travel-time misfit function is quasilinear with respect to changes in reservoir properties. As a result, the minimization proceeds rapidly even if the prior model is not close to the solution. Second, the computational cost associated with the sensitivity computation depends only on the number of wells, which can be orders of magnitude lower than the number of parameters or the amount of observed data. This offers a tremendous advantage over the commonly used gradient simulator method or the conventional adjoint methods that attempt to minimize the production data directly. Furthermore, the travel time approach also offers computational advantage during minimization of the misfit function using the Gauss-Newton algorithm. We have presented several examples to demonstrate the power, generality, and practical feasibility of our proposed approach for large-scale field applications.
Geologic and Economic Significance of the Upper Morrow Chert Conglomerate Reservoir of the Anadarko Basin
Authors: Shelby J.M.
Published: December 2007

The Upper Morrow chert conglomerate is recognized and described for its geologic significance as a new stratigraphic unit and for its economic significance as a reservoir, which has prompted the current deep drilling activity in the Anadarko basin of Texas and Oklahoma.

Introduction

The Upper Morrow chert conglomerate is a previously unrecognized stratigraphic marker and is one of the most significant gas reservoirs in the western Anadarko basin. It continues to be the object of a widespread exploratory effort in Hemphill and Wheeler counties in Texas and in Roger Mills, Beckham, and Washita counties in Oklahoma. These counties sit astride the axis of the basin and are near the Amarillo-Wichita mountain front (Fig. 1). Drilling to depths greater than 16,000 ft (4900 m) sometimes is required to reach these elusive stratigraphic traps; therefore, knowledge of the depositional environment of these Lower Pennsylvanian Morrow chert conglomerates is necessary to reduce exploratory risk. These chert conglomerates seem to fit a fan delta model, with elongate distributary channels carrying coarse sediments into a shallow marine environment.The reservoir usually is overpressured in the deeper part of the basin and may have a reserve of 1 Bcf/ft (93 million m3/m) of effective porosity on the 640-acre (2.59-km2) drilling unit. Pay thickness may exceed 50 ft (15 m), and deliverabilities of 10 MMcf/D (283 000 m3/d) are not uncommon.Before the discovery of the Shreikey field in Roberts County, TX, in 1974, little was known about the Upper Morrow chert conglomerates except from cores on one or two wells in Hemphill and Roberts counties, TX. Since the Shreikey discovery, this zone has prompted much of the deep exploratory drilling in the basin, with successful efforts in fields such as Buffalo Wallow, Reydon, Cheyenne, Elk City, and in recent discoveries.

Regional Setting

The Anadarko basin covers an area of approximately 35,000 sq miles (90 000 km2) stretching across northwestern Oklahoma, the northeastern Texas Panhandle, southwestern Kansas, and southeastern Colorado. The Morrow chert conglomerates are confined to a relatively small area in the eastern Texas Panhandle and western Oklahoma (Fig. 2). The basin is asymmetrical with its short limb and axis adjacent and parallel to the northwest-southeast trending Amarillo-Wichita uplift. This leads to an easy subdivision into mountain front, basin axis, and shelf area.Major orogenic movements occurred in late Devonian, post-Mississippian/pre-Morrowan, and post-Morrowan/pre-Des Moinesnian time, with the latter episodes producing most of the tectonic features of the area, including uplift, folding, and erosion of the Amarillo-Wichita Mountains and frontal area. The axes of faulted anticlines trend subparallel to the major uplift.

JPT

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