bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Integrated Reservoir Characterization Study Matching Production Data and 4D Seismic
Authors: Kretz Vincent , Ravalec-Dupin Mickaële Le , Roggero Frédéric 
Published: December 2007

Summary
Our purpose is to evaluate the benefit of using time-lapse seismic in addition to production history for reservoir characterization. A new inversion methodology, based on the gradual deformation method (GDM), has been developed to simultaneously integrate different sources of information like 4D-seismic-related data and production data. This methodology was validated successfully on a geologically realistic 3D synthetic reservoir model.
An optimization procedure was developed to identify reservoir models consistent both with an initial 8-year period of production data and with 4D-seismic-related data. The procedure is based on two complementary numerical tools developed at the Inst. Français du Pétrole: the Fast Fourier Transform—Moving Average (FFT-MA) generator and the GDM. The first tool generates stochastic realizations for the reservoir model; the second tool allows us to perturb the realizations from a small number of parameters while preserving the spatial-variability model. The optimization process was repeated starting from different initial reservoir models. The predictive quality of the constrained reservoir models was estimated by comparing the simulated forecasts and the reference data for a second 8-year period of production data.
The proposed inversion method proved its efficiency for constraining geostatistical reservoir models to different sources of data. It is shown that conditioning reservoir models to saturation changes in addition to production data results in significant improvement in the reliability of production forecasts. The present study goes one step further than the study by Kretz et al.,1 which was dedicated to the integration of accurate gas-saturation data into the reservoir model. Because such accurate data are rarely available, we focus on a more realistic case: we estimate the usefulness of binary data, indicating the presence or absence of gas.
Numerical Studies of Gas Production From Class 2 and Class 3 Hydrate Accumulations at the Mallik Site, Mackenzie Delta, Canada
Authors: Moridis G. J. 
Published: December 2007

Summary
The Mallik site represents an onshore permafrost-associated methane hydrate accumulation in the Mackenzie Delta, Northwest Territories, Canada. This study focuses on gas production at the Mallik site from hydrate deposits that are underlain by either a free-water zone (Class 2) or an impermeable boundary (Class 3). The production analysis was conducted with a numerical simulator that can model the nonisothermal CH4 release, phase behavior, and flow under conditions typical of CH4-hydrate deposits by solving the coupled equations of mass and heat balance. Accumulations with a CH4-hydrate saturation of at least 50% were studied. Dissociation was induced mainly by a combination of thermal stimulation and depressurization as hot fluids circulated between injection and production wells. The effects of salinity and of pressure changes at the wells were also accounted for. The production strategy resulted in a zero net water production. The simulation results indicated that the amount of CH4 released from the dissociating hydrate deposits is sensitive to the hydrate saturation, the initial temperature, the specific enthalpy, and the flow rate of the circulating fluids.
Slaughter Estate Unit CO2 Pilot - Surface and Downhole Equipment Construction and Operation in the Presence of H2S
Authors: Adams Gene H. , Rowe Hunter G. 
Published: December 2007

Summary
This paper presents the material selection, construction procedures, safety devices, corrosion control and monitoring, and operational procedures necessary for successful compression, transportation, and injection of a gas stream containing 28% hydrogen sulfide. It also discusses various operational problems encountered during the 3-year project life.

Introduction
As Amoco's West Texas waterfloods in the San Andres formation matured, it became evident that they would reach their peak production levels and begin to decline in the early 1970's. It also became evident that recovery of original oil in place through primary and secondary means would be in the range of 25 to 45%. The large quantities of oil which would remain unrecovered led to considerations of tertiary recovery methods.Although much laboratory work had been done in studying tertiary recovery processes, it was recognized that only field testing in a reservoir environment could prove the economic viability of the various tertiary methods. Screening of possible recovery techniques led to the selection of the miscible displacement process as having the most promise in these reservoirs. A company-wide search was made in late 1970 for possible tertiary project sites, and several pilot sites were selected to test the various miscible agents.A portion of the Slaughter Estate Unit which had not been waterflooded was selected as a site for a pilot test of the CO2 miscible displacement process. Fig. 1 shows the location of the Slaughter field in relationship to the West Texas - eastern New Mexico area. Fig. 2 shows the location of the Slaughter Estate Unit within Slaughter field. Eight pilot wells were drilled from March through June 1972, and waterflood operations began in Nov. 1972. Peak secondary oil production was seen in mid-1973, and by mid-1976 a steady secondary decline rate was discernible.It soon was determined that at projected injection rates a reliable source of pure CO2 in sufficient quantities and a means of delivering it to the pilot site did not exist. There was, however, a feed gas stream to the Claus sulfur unit at the Slaughter gasoline plant, about 7 miles (11.3 km) from the pilot site, which consisted of approximately 72% carbon dioxide and 28% hydrogen sulfide. Investigations ascertained that there were no commercially available processes for completely separating the hydrogen sulfide and carbon dioxide in the Claus plant feed gas (hereafter referred to as acid gas). Further, laboratory tests showed that the displacement process using acid gas as a solvent was the same as when CO2 was used. Preparations were made, therefore, to compress the acid gas stream and to transport it through a transmission line to the pilot wellsite.Of course, there was never any consideration given at any time to the use of the acid gas stream as a miscible agent during full-scale field flooding. In any case it would have provided only a tiny fraction of the required volumes of CO2.
JPT
P. 1065^
Cubic Equations of State Applied to HT/HP and Highly Aromatic Fluids
Authors: Pedersen K. S. , Milter J. , Sørensen H. 
Published: December 2007

Summary
Pressure/volume/temperature (PVT) data are presented for 38 reservoir fluids including fluids dominated by paraffins, heavy aromatic fluids with a significant content of C81+, and high-temperature/high-pressure (HT/HP) reservoir fluids. By properly taking into account the compositional differences, these fluid types can all be represented using a classical cubic [Soave-RedlichKwong (SRK) or Peng-Robinson (PR)] equation of state (EOS) with volume correction. The plus fraction is split into carbon number fractions and EOS model parameters assigned to each fraction. To keep the number of components at a manageable level, the carbon number fractions are lumped into pseudocomponents, each containing several carbon number fractions. Hydrocarbons as heavy as C200 are considered when splitting up the plus fraction. Neglecting the content of components heavier than C80 will give a false picture of the phase behavior of heavy aromatic fluids. Correlations are presented for Tc, Pc, and w as a function of molecular weight and density. Problems are experienced representing the thermal expansion of stable oils using a cubic EOS in the classical form. It is shown that this deficiency can be cured by introduction of a temperature-dependent volume correction term.
Thermal Behavior During Restart of Ultradeepwater Flowlines
Authors: Golczynski T. S. , Niesen V. G. 
Published: December 2007

Summary
For subsea tiebacks in ultradeep water, restarting from shut-in conditions can pose significant flow-assurance issues, particularly with respect to hydrate formation. Achievable restart rates are a function of available hydrate inhibition and shut-in conditions. The overall chemical volume required is highly dependent upon the tieback type, length, and insulation level. Current practice is to evaluate alternate procedures, such as preheating the flowline to reduce warm-up times and chemical requirements.
Alkaline Injection for Enhanced Oil Recovery - A Status Report
Authors: Mayer E.H. , Berg R.L. , Carmichael J.D. , Weinbrandt R.M. 
Published: December 2007

Summary
In the past several years, there has been renewed interest in enhanced oil recovery (EOR) by alkaline injection. Alkaline solutions also are being used as preflushes in micellar/polymer projects. Several major field tests of alkaline flooding are planned. are in progress, or recently have been completed. Considerable basic research on alkaline injection has been published recently, and more is in progress. This paper summarizes known Field tests and. where available, the amount of alkali injected and the performance results. Recent laboratory work, much sponsored by the U.S. DOE, and the findings are described. Alkaline flood field test plans for new projects are summarized.

Introduction and Past Technology
The history of alkaline flooding, dates back- to the early 1920's, with roots in the combination of reservoir engineering and chemistry. Understanding, the interaction of the injected alkaline chemicals with the reservoir oil, water, and rock is a chemical problem, while using the interactions to improve oil recovery is a reservoir engineering problem. Alkaline oil recovery has been attributed to oil/alkali interaction (called "emulsification"), to alkali/rock interaction (called "wettability alteration"), and to chemical precipitation caused by mixing of the injected alkaline solution with the hardness ions in reservoir water. Any or all of these mechanisms can operate in a particular application. Because of the interplay of these mechanisms, alkaline flooding is ail extremely complex oil recovery process and tends to be site-specific in terms of process design and dominant recovery mechanism. Some of the apparent differences in the use of alkali cited in the literature result from the site-specific nature of a process that uses different mechanisms to improve oil recovery in different reservoirs. For this reason, most of the disagreement in the literature can be explained by differences in the recovery processes active in an individual reservoir, Recognition of the individual mechanisms should allow profitable application of alkaline flooding to a wide range of reservoir types. The first attempt to bring together what was known about alkaline flooding was made by Johnson' in 1975. He summarized Field data that had been published and the technology as it then was understood. From 1975 through 1979, when this paper was first written, the number of field tests concluded and described, begun, or planned grew as did research on the processes involved. It became evident that alkaline flooding was not a simplistic technique for enhancing oil recovery but rather a very complex one. From 1979 through mid-1982, the number of field tests planned and initiated increased markedly. This increase is attributed to the favorable economics created by the U.S. DOE's Tertiary Incentive Program. During the program's life from Aug. 1979 through Jan. 1981, 41 alkaline flood projects were certified.
JPT
P. 209^
Reservoir Permeability Determination Using After-Closure Period Analysis of Calibration Tests
Authors: Benelkadi Said , Tiab Djebbar 
Published: December 2007

SummaryHydraulic fracturing generally has been limited to relatively low-permeability reservoirs. In recent years, the use of hydraulic fracturing has expanded significantly to high-permeability reservoirs. The objectives of fracturing low-permeability reservoirs and high-permeability reservoirs are defined by reservoir parameters.The estimation of reservoir permeability, a variable of great importance in hydraulic fracturing design, is frequently unknown because either candidate wells do not flow or pretreatment pressure-transient testing is required. Consequently, Nolte et al.1 introduced a new method for adding after-closure fracturing analysis to the pretreatment calibration testing sequence that defines fracture geometry and fluid-loss characteristics. The exhibition of the radial flow is ensured by conducting a specialized calibration test called the minifalloff test. Using the theory of impulse testing and the principle of superposition, Nolte et al.1 developed a method that allows the identification of radial flow and, thus, the determination of reservoir transmissibility and reservoir pressure.This work proposes a new method for determining reservoir permeability. The method also offers the potential for determining the average reservoir pressure. This procedure is based on the use of the pressure derivative, and it requires only one log-log plot for the identification of the radial-flow regime and the determination of reservoir parameters.The application of the proposed method is demonstrated on real field data from calibration tests performed on several oil and gas wells. The reservoir parameters (particularly permeability) determined with this method are verified by comparison with results obtained from pressure-buildup tests. Other sources, such as core analysis, lend support to the permeability estimated with the proposed technique.
An Equation for Calculating Skin Factor Due to Restricted Entry
Authors: Odeh A.S. 
Published: December 2007

Two publications give the skin factor due to restricted entry to flow at thewellbore. Restricted entry occurs when only part of the productive sand is opento flow. This can be caused by partial penetration or by perforating a portionof the sand. penetration or by perforating a portion of the sand. It isrecognized that in some cases restricted entry may be due to pluggedperforations or to insufficient number of perforations. This situation, thoughit will result in an additional skin factor, is not what is discussed in thisarticle. One of the publications gives the skin factor for three cases. Thefirst is for a partially penetrating well; the second is for a well producingfrom only the central portion of the productive interval; and the third is fora well in which several equally spaced intervals are open to flow. The secondpublication presents charts for estimating the skin factor when presents chartsfor estimating the skin factor when the open interval starts at eight differentlocations and covers a range of thickness of 20 to 200 ft. In this article skinfactor as a function of sand thickness, location of the open interval, and thewellbore radius is given in a general equation form:
ht 0.825 kH Sr = 1.35 ----- ---1 {1n ht -------- + 7) hp kV
kH - 0.49 + 0.1 1n h ---------- kV
.1n r - 1.95}, .............................(1) wc
where
Sr = skin factor due to restricted entry, ht = total sand thickness, ft (m), hp = length of perforated interval, ft (m), kH/kV = ratio of horizontal tovertical permeability, rwc = corrected wellbore radius, ft (m), and is givenby
0.2126(Zm/ht + 2.753) r = r e wc w
for y greater than 0, and rwc = rw for y=0,
y = distance between the top of the sand and the top of the open interval, and zm = distance between the top of the sand and the middle of the openinterval.
The relation between y, hp, and Zm is
Zm = y+hp/2...........................................(2)
Because of symmetry, Zm/ht 0.5. A plot of rwc/rw vs. Zm illustrating thesymmetry is shown in Fig. 1.
Discussion of Eq. 1
The radius of drainage rd does not appear in Eq. 1. This is because sr isvery insensitive to rd. For example, an increase in rd from 330 to 6,600 ftincreases Sr from 43.38 to 43.50, when ht=300, y = 0, and rw = 0.25. The valueof sr is most sensitive to the ratio of the open interval to the sandthickness, and to the sand thickness. Comparison between sr values calculatedby Eq. 1 and read from Refs. 1 and 2 is given in Fig. 2. The comparison isgood, and Eq. 1 is adequate for engineering calculations. The use of Eq.1 isillustrated by the following example. Calculate Sr when ht=200 ft, hp=40 ft, rw= 0.25ft, and y=80ft.
P. 964
An Efficient Discrete-Fracture Model Applicable for General-Purpose Reservoir Simulators
Authors: Karimi-Fard M. , Durlofsky L. J. , Aziz K. 
Published: December 2007

Summary
A simplified discrete-fracture model suitable for use with general-purpose reservoir simulators is presented. The model handles both 2- and 3D systems and includes fracture-fracture, matrix-fracture, and matrix-matrix connections. The formulation applies an unstructured control volume finite-difference technique with a two-point flux approximation. The implementation is generally compatible with any simulator that represents grid connections by a connectivity list. A specialized treatment based on a "star-delta" transformation is introduced to eliminate control volumes at fracture intersections. These control volumes would otherwise act to reduce numerical stability and timestep size. The performance of the method is demonstrated for several oil/water flow cases including a simple 2D system, a more complex 3D fracture network, a localized fractured region with strong capillary pressure effects, and a model of a strike-slip fault zone. The discrete-fracture model is shown to provide results in close agreement with those of a reference finite-difference simulator in cases in which direct comparisons are possible.
Marlin Failure Analysis and Redesign: Part 1 — Description of Failure
Authors: Bradford D. W. , Fritchie D. G. , Gibson D. H. , Gosch S. W. , Pattillo P. D. , Sharp J. W. , Taylor C. E. 
Published: December 2007

This is the first of three related papers that describe the actions of an incident-investigation team formed to evaluate the failure of Well A-2 on the Marlin tension-leg platform (TLP). This paper outlines several possible failure modes and narrows the field of candidate failure modes to a small subset by deduction from both analysis and physical evidence. The application of these results and analytical techniques, as incorporated into the redesign of the subsequent completions, is addressed in the second paper of the series. The third paper discusses real-time monitoring of the redesigned completions.

Abstract
The Marlin field is located in the Gulf of Mexico, Viosca Knoll Blocks 871/915, and was originally intended to be produced from a TLP by means of five predrilled dry-tree penetrations. First production from Well A-2 began in November 1999. Shortly thereafter, a minor but persistent tubing leak occurred. Between 7 and 20 November, Well A-2 was alternately flowing and shut in, depending on the shakedown of surface equipment and pipeline availability. On 20 November, the casing pressure jumped to shut-in tubing pressure, signifying a major tubing failure.
This paper describes the actions of an incident-investigation team formed to evaluate the failure of Well A-2. Possible failure modes investigated by the team include:
Helical buckling of the production tubing, with or without the combined loss of a tubing centralizer. Crushing of the tubing by ratcheting displacement from a failed centralizer. Lateral deflection of the subsea wellhead. Collapse of the production (and/or intermediate) casing onto the tubing because of one or a combination of the following. Hydrate formation outside the intermediate casing owing to gas migration from a shallow hydrocarbon zone with subsequent dissolution during initial production. Nonuniform loading of the production casing because of the geometry of the submudline packoff tubing hanger (POTH) slips. Leak in a production-casing connection. Annular fluid expansion (AFE). Formation of a heat pipe in the production tubing by production casing/riser annulus. Casing wear on the intermediate casing. Excessive initial pressure resulting from setting the casing hanger seal assembly in the subsea wellhead. Inadequate performance of the tubing or casing caused by either an incorrectly run or an inadequately manufactured joint.
Deducing from both analysis and physical evidence, the current installment will narrow the field of candidate failure modes to a small subset. Applying these results and analytical techniques, as incorporated into the redesign of the subsequent completions, is addressed in the second paper of the series.1 The final paper describes the implementation of the redesign as an insulatedtubing completion.2
Selective Flotation of Casing From a Floating Vessel
Authors: Rae G. , Williams H. , Hamilton J. 
Published: December 2007

Summary
This paper outlines a new technique for running production casing from semisubmersible drilling rigs on highly deviated wells that was used for the first time on the Captain field, United Kingdom Continental Shelf (UKCS), operated by ChevronTexaco. The process, which incorporates selective-flotation techniques in which air at atmospheric pressure is trapped in the bottom of the casing string to lighten the casing during deployment in the high-angle part of a highly deviated well, has been used successfully on four subsea wells to date. This is believed to be the first implementation of this technique on semisubmersible rigs.
Productivity Changes in Reservoirs With Stress-Dependent Permeability
Authors: Raghavan R. , Chin L. Y. 
Published: December 2007

SummaryThe goal of this paper is to present correlations to permit engineers to evaluate productivity losses in reservoirs with stress-dependent permeability (stress-sensitive reservoirs). The correlations developed in this study are intended to be used in determining production forecasts. For stress-sensitive reservoirs, the reduction in permeability caused by the change in the stress state during production (if any) may significantly reduce expected productivity. It is the purpose of this paper to address methods to ascertain changes in productivity as a result of stress-dependent permeability. A rigorous mathematical model that couples geomechanical and fluid-flow aspects is used to correlate productivity reductions with time. The reduction in the productivity index (PI) is quantified by a skin factor and is expressed as a function of operating variables such as overburden stress, mechanical properties, wellbore pressure, and drainage area. The expressions developed in this study may be incorporated directly (after tuning) in simulators to properly account for changes in productivity.