bluuebunny/crossref_metadata_2025 huggingface dataset:
Comparison of Measured and Predicted Pressure Drops in Tubing for High-Water-Cut Gas Wells
Authors: Reinicke K. M. , Remer R. J. , Hueni G.
Published: December 2007

A considerable number of deep (>3000 m [> 10,000 ft]) high-volume gas wells in northern Germany show signs of increasing water production (about 800 × 10−6 m3/std m3 [135 bbl/MMscf]), This paper presents results of tests in gas wells to measure the two-phase (gas/water) pressure drop in the tubing. Experimental data are evaluated and compared with the calculations from over 15 different pressure prediction schemes. Modifications proposed for some of the methods resulted in significantly improved predictions.
Development and Testing of New Offshore Cathodic Protection Criteria
Authors: Evans Sheldon
Published: December 2007

New sacrificial anode protection criteria developed and tested by Dubai Petroleum Co. (DPC) resulted in a 40% decrease in anode weight as compared to that required by conventionally accepted design. Derivation of the criteria is based on an analysis of extensive field results of potential surveys of seven DPC platforms that had conventional sacrificial anode protection systems. It was found that an initial platform current density of 29±2 × 10−3 A/sq ft [310±20 mA/m2] of area exposed to seawater resulted in polarization of the platform to −1 V with respect to the silver/silver-chloride reference electrode. As a consequence of this high initial polarization, the electric current requirement for protection is reduced significantly. The new criteria were used in the design of Platform JJ, which was installed in Sept. 1982. Field results that include periodic potential surveys of Platform JJ are presented and discussed.
DST Flow Rates From Two Horner Slopes
Authors: Mackett R.A.
Published: December 2007

The slopes of the initial and final shut-in periods of a drillstem test (DST) are used to calculate the corresponding flow rates knowing the recorded flow times and the total liquid recovery and assuming constant transmissibility. Examples of the calculation are included for a closed-chamber test and a conventional test from Earlougher.1

Calculations

" If the shut-in period is long enough, and if wellbore storage is not dominant, a Horner plot of buildup data should have a straight-line section with slope -m." 1 The value of the slope of the Horner plot may be used to calculate the transmissibility:Equation 1

The value of the constant 162.6 is 2121 for the corresponding SI units listed in the Nomenclature. The following derivation is based on the assumption of constant transmissibility and a flow regime in which the Horner analysis is valid (see Discussion):Equation 2, 3, and 4

Substituting Eqs. 3 and 4 into Eq. 2 and rearranging yieldsEquation 5

whereEquation 6

SubstitutingEquation 7

into Eq. 5 yieldsEquation

Rearranging results inEquation 8

Eqs. 7 and 8 used to allocate recovered liquid volumes between the initial and final flow periods.

Example 1: A Closed-Chamber DST

A northwest Alberta well, Well 6–4-65–20W5, had a straddle-packer DST run at a depth of 5,653 ft [1720 m] in 7 7/8-in. [200-mm] hole with 442 ft [134.7 m] of 2.875-in.- [73-mm]-ID drill collars. A 9.1-lbm/gal [1090-kg/m3] gel chemical mud resulted in an initial and final hydrostatic mud pressure of 2,736 psi [18 864 kPa]. The preflow was 10 minutes with corresponding final pressure of 161 psi [1110 kPa]. The initial shut-in time and pressure were 90 minutes and 2,153 psi [14 844 kPa]. The pressure at the beginning of the second flow was 106 psi [730 kPa], building to 561 psi [3868 kPa] over 90 minutes, and the final shut-in pressure was recorded as 2,121 psi [14 624 kPa]. The slopes of the Horner plot for the initial and final shut-in periods were 107.6 and 127.4 psi/cycle [741.9 and 878.4 kPa/cycle], respectively. The formation temperature was 119°F [48.3°C] and the net pay was 7 ft [2.1 m]. The operator (Mobil Oil Canada) calculated a total fluid recovery of 400 ft [122 m], composed of 340 ft [103.7 m] of 26°API [898.4-kg/m3] oil with a viscosity of 4.05 cp [4.05 mPa·s], and 60 ft [18.3 m] of oil-cut mud from closed-chamber calculations and a production rate of 46 B/D [7.4 m3/d].
The Viscosity of Natural Gases
Authors: Lee Anthony L. , Gonzalez Mario H. , Eakin Bertram E.
Published: December 2007

Experimental viscosity and density data of four natural gases are presented for temperatures from 100 to 340 F and pressures from 100 to 8,000 psia. A correlation is discussed and results reported.

Introduction

This investigation is one of several efforts by the authors to provide viscosity data for pure hydrocarbons and mixtures. Results of some pure hydrocarbons and their mixtures have been presented. Several predictive methods and correlations have also been reported. This paper presents the experimental viscosity and density data of four natural gases and confirms a correlation in a previous study.

APPARATUS

The viscometer was described previously. A bank of stainless steel pycnometers was included to determine density in conjunction with the viscosity measurements (Fig. 1).

DATA AND MATERIALS

The natural gases were furnished by the Atlantic Richfield Co. (Samples 1 and 2), the Continental Oil Co. (Sample 3) and the Pan American Petroleum Corp. (Sample 4). Table 1 shows the composition of these gases obtained by mass spectrometer analysis. The pure component viscosity data used in the correlation have been published. Experimental and calculated viscosity data for the natural gases are presented in Tables 2 through 5.

CORRELATION

Starling and Ellington have reported several semi-empirical expressions based to a certain extent on the theory of viscosity advanced by Born and Green. The final expression presented by Starling and Ellington is:

(micropoise)= o exp[X(T) pY(T)]....... (1)

Eq.1 was modified by Lee et al. to represent mixture and pure component data simultaneously. This equation has the form:

..........(2)

where

K= ..........(3)

X= ..........(4)

Y= ..........(5)

Over the pressure and temperature range studied in this investigation, this equation represents the data on methane, ethane, propane, n-butane and four methane-n-butane mixtures with a standard deviation* of 1.89 per cent. Density data by Sage and Lacey were used to fit the equations. Eq. 2 gives reliable values of the viscosity of light hydrocarbons without prior knowledge of experimental viscosity values, but accurate density data must be available. Eq. 2 was used to predict viscosity values for the natural gases studied in this paper. The particular set of parameters contained in Eqs. 3 through 5 gave values that reproduced experimental data within 5 per cent. Needless to say, in using Eq. 2 better density values will give better viscosity results. However, those engineers who do not have accurate density values at hand or the time, or such facilities as a library. computer, etc. readily available, may feel uneasy in using Eq. 2. Therefore, the authors sought the easiest but by no means best density prediction method, which was reported by Kay 30 years ago. A set of density values, which were calculated based on Kay's method, and a generalized compressibility factor chart were used to fit Eq. 2.

JPT

P. 997ˆ
Air Drilling Operations Improved by Percussion-Bit/Hammer-Tool Tandem
Authors: Whiteley Maxwell C. , England William P.
Published: December 2007

Contractors and operators air drill whenever possible to improve rate of penetration (ROP). This is done with pneumatic hammer tools (HT's) and various bit types used with standard rotary air rigs. The recent application of a "flat-bottomed" percussion bit (FPB) combined with a custom-designed HT originally developed for mining operations has significantly improved air drilling operations in the Arkoma basin. The improvements include a large increase in ROP, improved hole geometry, reduced drillstring stresses, and a substantial reduction in cost per foot. This paper provides (1) a discussion of the engineering design and operation of the FPB/HT tandem, (2) applications and limitations of the tools, (3) guidelines for optimization of performance, and (4) documentation of field performance on Arkoma basin wells to demonstrate the improvements in air drilling operations.
Triaxial-Load-Capacity Diagrams Provide a New Approach to Casing and Tubing Design Analysis
Authors: Johnson Rick , Jellison Michael J. , Klementich Erich F.
Published: December 2007

A computer program has been developed that generates a two-dimensional (2D) graphic representation to display the effect of anticipated service conditions on specific casing and tubing. The triaxial-load-capacity diagram permits a visual determination of string design adequacy by both API and equivalent-triaxial-stress design factors. The program is useful in the design and analysis of any casing or tubing string.
Measurement of Drilling Properties
Authors: Gault Allen D.
Published: December 2007

Rock-bit performance is related here to formation strength. Bingham mathematical models and steel-tooth rock bits are used in a procedure to optimize rates of penetration (ROP's) and to extend bit life.

The ability to distinguish elastic formations from plastic formations has been used to introduce polycrystalline-diamond-composite (PDC) bits in the Gulf of Mexico, where shale is the predominant formation. The validity of the mathematical models has been confirmed on long, homogeneous shale sections, and the models have also been expanded to include soft-formation insert rock bits.
Deepwater Drilling Riser System
Authors: Chastain T. , Stone D.
Published: December 2007

The principal focus of this paper is to discuss and summarize, from the manufacturer's perspective, the primary milestones in the development of the marine riser system used to drill in record water depths off the U.S. east coast.

This riser system is unique in that it used advanced designs, material technology, and quality control to enable safe operation in water depths beyond the capability of conventional drilling riser systems. Experience and research have led to design improvements that are now being incorporated in new riser systems that have the potential of expanding the frontiers to increasingly deeper water.
Formation Productivity Evaluation From Temperature Logs
Authors: Bird J.M. , Frost N.
Published: December 2007

A brief review is presented of the methods of quantitative evaluation of borehole temperature logs as applied to gas flow measurements. A method for evaluation of the formation productivity is introduced, making use of a temperature log of the flowing gas well, the reservoir temperature and pressure and the Joule-Thomson expansion temperature of the gas. A method is discussed for applying a scale to the temperature log. Its use for obtaining a better understanding of both natural and man-made formation fractures is proposed

Introduction

In previous work on the quantitative evaluation of borehole parameters through the use of temperature logs, Bird and others made use of a function delta of the variation of the earth's and the borehole fluid temperatures with depth. Kunz and Tixier have referred to this function as the subtangentAfter a brief review of the use of temperature logs for measuring the volume of gas flow in a borehole, this paper deals with the application of temperature logs to evaluate the mechanism of gas production.

Determination of Gas Volume From a Temperature Log

Fig.1 illustrates a graphical method of determining the quantity delta. This figure shows the shape of a standard temperature log in a gas producing zone. Delta is defined as

where T, is for practical purposes the earth temperature, Tg, is the gas temperature and is the rate of change of gas temperature with depth. Fig. 2 is a plot of delta vs gas production rate. This figure was taken from Schonblom. The dots represent data taken in boreholes less than 5 1/2-in. diameter, the circles for boreholes between 5 1/2 to 7 1/2-in. and the squares for boreholes greater than 7 1/2-in. diameter. Schonblom, on a theoretical basis, concluded that the curve had to be discontinuous. The straight line on the left side represents the laminar portion and the curve on the right side represents the turbulent mode. Admittedly, the distribution of points in this figure looks distressing.

JPT

P. 301ˆ
Use of a Hybrid Grid in Reservoir Simulation
Authors: Pedrosa Oswaldo A. , Aziz Khalid
Published: December 2007

A technique is presented to improve the treatment of wells in reservoir simulators by the use of an orthogonal curvilinear grid (cylindrical or elliptical) in well regions and a rectangular grid elsewhere in the reservoir. Special methods are developed to handle irregular blocks connecting the two types of regions. The nonlinear equations for the two Regions are solved with different levels of implicitness; the simultaneous solution (implicit) method is applied to the well regions, while an implicit pressure, explicit saturation (IMPES) technique is used for the reservoir region. An efficient approach, requiring no outer iterations, between well and reservoir regions is used to couple different regions. The scheme is validated by the simulation of the flow of a slightly compressible fluid in a square domain with one boundary open to flow. For this case, the numerical solution with the hybrid grid approach matches the analytical solution exactly. A computer model based on the approach was developed for simulating two-phase flow in multiwell horizontal reservoirs. We show that* the proposed technique provides much better prediction of the phase split in the producers than the conventional approach.
Local Mesh Refinement and Modeling of Faults and Pinchouts
Authors: Forsyth P. A. , Sammon P. H.
Published: December 2007

Completely flexible gridblock connections are necessary for local mesh refinement and modeling of faults and pinchouts. For practical purposes, it is necessary to combine such arbitrary connectivity with an adaptive implicit technique. In this paper, the methods used to discretize the flow equations for unusual geometries is discussed, and a rigorous analysis is given. A completely general, sparse, incomplete LU iterative solver is described that can solve Jacobian matrices with arbitrary connectivity. Various test results are presented.
Block-Preconditioned Conjugate-Gradient-Like Methods for Numerical Reservoir Simulation
Authors: Eisenstat Stanley C. , Elman Howard C. , Schultz Martin H.
Published: December 2007

We describe a collection of block preconditioners for use in solving large, sparse, linear systems of equations by iterative methods, and we compare their performance with several point preconditioners in solving some systems arising in numerical reservoir simulation. We consider block preconditioners that handle either lines or planes in an implicit manner and pointwise incomplete LU (ILU) factorizations combined with partial elimination preprocessors. We conclude that the best of the pointwise methods are both more robust and faster, but that the best of the block methods are competitive for certain orderings of unknowns and require less storage.
The Role of Bicarbonate Ion in Calcite Scale Formation
Authors: Przybylinski John L.
Published: December 2007

In this paper, we study the influence of the seed surface area, supersaturation ratio, bicarbonate ion concentration, and pH on the calcite precipitation rate. All other things being constant, the rate is a nearly linear function of seed surface area and supersaturation ratio. The rate also, surprisingly, depends on the concentration of bicarbonate ion, which is not a thermodynamically relevant species. There is no discernable effect of pH on the rate after the effects of pH on the supersaturation ratio and bicarbonate ion concentration are accounted for.
A Buffer-Regulated HF Acid for Sandstone Acidizing to 550°F
Authors: Scheuerman R. F.
Published: December 2007

Two earlier papers discussed the suitability of buffer-regulated HF acid (BRHFA) for high-temperature sandstone matrix stimulation treatments. Acetic-acid/acetate buffering (pH=4.5 to 5.0) limited corrosion to acceptable levels at temperatures up to about 350°F [177°C]. Subsequent development of reservoirs with terhperatures approaching 450°F [232°C] demonstrated a need for even higher-temperature acidizing systems.

This paper discusses a new, less corrosive BRHFA formulation that has clay-dissolving capacity comparable to 7½% HCl/1½% HF acid. The corrosion rate of carbon steel at 550°F [288°C] is only 330 mils/yr [8.4 mm/a]. The BRHFA systems are also compatible with a variety of coirosion-resistant alloys.

This paper presents clay slurry, core flow, arid corrosion data and discusses use guidelines.
Gravity Effects in the Displacement of Oil by Surfactant Solutions
Authors: Hornof V. , Morrow N. R.
Published: December 2007

The displacement of isooctane by aqueous surfactant solutions was investigated in model porous media consisting of a thin layer of lightly sintered glass beads. Pre-equilibrated oil/surfactant pairs were prepared that exhibited interfacial tensions (IFT's) in the range 0.06 to 2.08 mN/m [0.06 to 2.08 dynes/cm]. Because aqueous solution viscosity was always higher than that of the isooctane, a stable displacement would normally be expected. While systems with IFT's greater than about 1 mN/m [1 dyne/cm] showed sharp interfaces and generally stable displacements, experiments conducted at lower IFT exhibited a considerable degree of instability. In particular, at lower tensions, the interfaces became fuzzy, and there was distinct evidence of gravity underride by the aqueous phase. The onset of gravity segregation with decreasing IFT was successfully related to capillary and viscpus forces operating within the systems. The degree of instability was found to increase with decreasing IFT, but oil recoveries did not necessarily decrease because of recovery mechanisms that involved mobilization and coalescence of zones of bypassed oil.
Dispersion of a Solvent Slug Injected Into a Communication Path
Authors: Schmidt Teddy , Heldrick Ted , Ridley Rod , Kissel Gerald
Published: December 2007

Solvents may be injected into a formation once communication has been achieved between injection and production wells to increase the size of the communication path. However, the solvent disperses into the formation and bitumen flows into the communication path, increasing the viscosity of the flowing phase. As a result, no solvent may ever appear at the producing well.

In this paper, the problem is modeled for the one-dimensional (ID) case and an analytic solution is obtained from which breakthrough time, outlet concentration of solvent, and other significant parameters can be estimated.
Steamdrive Performance in a Layered Reservoir—A Simulation Sensitivity Study
Authors: Spivak Allan , Muscatello J. A.
Published: December 2007

This paper describes the use of a thermal reservoir simulator to study steamdrive in a reservoir consisting of noncommunieating sand layers. The simulator was used to determine basic design parameters for steamdrive operations in the South Belridge field, Kern County, CA. Sensitivity runs were made to investigate the effect of various parameters—such as spacing, steam quality, and steam injection rate—on performance. Comparisons were made of the performance of a layered system with no communication between layers and that of an identical system with vertical communication.
Examination of the Confined-Pattern Concept in Steamflood Simulation
Authors: Chu Chieh
Published: December 2007

The confined-pattern concept has been widely used in steamflood simulation for homogeneous reservoirs with negligible dipping. This work found that, for field projects with 9 to 100 repeated patterns, this concept underestimates the actual oil production by 3% at the end of 6 years. The usefulness of the concept has thus been ensured.
Analysis and Correlation of Nitrogen and Lean-Gas Miscibility Pressure
Authors: Firoozabadi Abbas , Aziz Khalid
Published: December 2007

The vaporizing gas drive (VGD) process was modeled with the Peng-Robinson equation of state (PR-EOS) and a compositional simulator. The comparison of numerical results with available experimental data has shown that the PR-EOS overestimates the minimum miscibility pressure (MMP), but it correctly shows that the length required to achieve miscibility is different for N2 and methane. Experimental data and some simulation runs have been used to develop a simple and reliable correlation for the prediction of MMP.
Design of Surface Facilities for Khuff Gas
Authors: Sood L. K. , Jamsheer A. S.
Published: December 2007

Although it was discovered in 1947, commercial exploitation of the Bahrain Khuff reservoir began in 1970. Current gas demand stands at 580 MMscf/D [16.4 × 106 std m3/d] and is growing rapidly. This paper briefly discusses the evolution of the design for surface facilities and field experience. The established design parameters could be used for the design of surface facilities for similar reservoirs.
Qatar NGL-2 Pipeline Problems
Authors: El-Jundi I. M.
Published: December 2007

The Qatar NGL-2 plant, commissioned in Dec. 1979, was designed to process the associated gas from the offshore crude oil fields of Qatar. The dehydrated, sour, lean gas and wet, sour liquids are transported by two separate lines to the Umm Said NGL complex about 120 km [75 miles] from the central offshore station. The 300-mm [12-in.] -diameter liquids line has suffered general and severe pitting corrosion, and the 600-mm [24-in.] -diameter lean gas line has suffered corrosion and extensive hydrogen-induced cracking (HIC or HIPC). Neither line performed to its design parameters, and many problems in the downstream facilities have been experienced. All efforts to clean the solids (debris) from the liquids lines have failed. This in turn interfered with the planned corrosion control program, thus allowing corrosion to continue. Various specialists have investigated the lines in an attempt to find the origin of the solids and to recommend necessary remedial actions. Should the lines fail from pitting corrosion, the effect of a leak at a pressure of about 11 000 kPa [1,595 psi] will be very dangerous, especially if it occurs onshore. To protect the NGL-2 operations against possible risks—both in terms of safety and of losses in revenue—critical sections of the pipelines have been replaced, and all gas liquids pipelines will be replaced soon. Supplementary documents to the API standards were prepared for the replaced pipelines.
Regional Caprock-Destroying Dolomite on the Middle Jurassic to Early Cretaceous Arabian Shelf
Authors: Broomhall R. W. , Allan J. R.
Published: December 2007

Massive, stratigraphically discordant dolomite occurs on the late Mesozoic Arabian Shelf in the northern portion of Aramco's main producing area. The dolomite is associated with solution-collapse of anhydrite seals and with enhancement of porosity and permeability in tight limestone seals within the region. By destroying regional caprocks, dolomitization has had an adverse effect on oil accumulation. The spatial distribution of this regional dolomite was mapped with wireline log and core data. Geochemical and fluid-inclusion analyses indicate that the dolomite formed from hot saline brines that were first expelled from halite-bearing evaporites, and then migrated into Arabian Shelf carbonates during burial.
Thermal Characteristics of Porous Rocks At Elevated Temperatures
Authors: Somerton W.H. , Boozer G.D.
Published: December 2007

Thermal diffusivities of some typical sedimentary rocks have been measured by a rapid unsteady-state technique. Thermal data including diffusivity and conductivity are presented for the temperature range of 200 to 1,800°F.

Diffusivities calculated from steady-state conductivity measurements compared favorably with unsteady-state data at the lower temperatures. Unsteady-state data are less reliable at higher temperatures; reported values may be as much as 20 per cent high at temperatures in excess of 1,500°F. This is caused partly by the simplified method used in calculating diffusivity from experimental data and partly by the many thermal reactions which occur at the higher temperatures.

The marked decrease in thermal diffusivity and conductivity at elevated temperatures indicates the importance of considering the temperature dependence of thermal properties in subsurface heat-transfer calculations. Knowledge of the effects of liquid saturation, overburden and pore pressures, and heats of reaction of reservoir materials will be required before complete subsurface thermal analyses may be made.

Introduction

Heat-transfer calculations are becoming increasingly important in the analysis of in situ combustion and underground nuclear explosions. Thermal data for natural rock materials at elevated temperatures are generally unavailable. Calculations at high temperatures may be grossly inaccurate if temperature-dependent thermal properties of rocks are not considered.

It is known that the heat capacities of rocks increase with temperature. Heat capacities may be calculated from chemical or mineralogical analyses of the rock system. Thermal bulk expansion of rocks is believed to be small, although few data are available. Thermal conductivities of most natural rock materials decrease with increased temperature. Thermal diffusivity, defined as the thermal conductivity divided by the product of the heat capacity and the bulk density of the material, is used in unsteady-state heat-transfer calculations. It is apparent that thermal diffusivity decreases markedly with increased temperature.
Cementation Exponents in Middle Eastern Carbonate Reservoirs
Authors: Focke J. W. , Munn D.
Published: December 2007

The cementation exponent, m, is a major factor of uncertainty in the calculation of hydrocarbon/ water saturation in heterogeneous carbonate reservoirs. Hydrocarbon saturations as high as 70 or 80%, calculated with the conventional value m = 2, may disappear completely with m values of 3 and 4 (Fig. 1), which are quite common in carbonate rocks. Laboratory data obtained in heterogeneous carbonate reservoirs often show a wide scatter (Fig. 2). Constant (average) m values are usually used in spite of such scatter, and data points with m values much higher than the average value are often rejected to obtain straight-line trends.

This paper presents the results of a study of the relationship between variable m values measured on core plugs and detailed carbonate rock types. The scatter in the data is analyzed in terms of rock type. We conclude that the high m values are often representative for specific rock types and that these values should not be rejected but applied selectively in log analysis over those intervals where these rock types occur.
Field Study of a New High-Temperature Fracturing Fluid in South Texas
Authors: Walser D. W.
Published: December 2007

Extensive field development of a new fracturing system incorporating a temperature-delayed crosslinker was undertaken over a 15-month period in south Texas. Treatments performed at depths from 7,500 to 17,100 ft [2290 to 5210 m] revealed that the new fluid has properties superior to those of high-temperature systems that use conventional organometallic crosslinkers. Treated formations include the Wilcox, Frio, and Vicksburg.

The use of this new fluid has resulted in lower and more consistent friction pressures. Average sand concentrations have been increased. A significant decline in the occurrence of screenouts has been observed.
Exact Solutions for Infinite-Conductivity Wells
Authors: Papatzacos Paul
Published: December 2007

In pressure transient testing, the infinite-conductivity condition translates mathematically into a uniform-pressure (or uniform-potential) condition at the well. This means the flux at different points of the well should be determined in such a way that potential remains uniform at the well. The integral equation for accomplishing this is solved analytically to yield the Laplace-transformed potential. For fractured-well problems, this leads to a relatively fast algorithm for drawing type curves directly on a computer screen. For limited-flow-entry problems, the analytical pressure expression can be used with the method of images to treat problems in reservoirs of finite thickness and/or areal extent.
Fracturing and Testing Case Study of Paludal, Tight, Lenticular Gas Sands
Authors: Warpinski N. R. , Branagan P. T. , Sattler A. R. , Lorenz J. C. , Northrop D. A. , Mann R. L. , Frohne K. -H.
Published: December 2007

This paper is a case study of the stimulation and testing of tight, lenticular sands in the paludal interval of the Mesaverde group in the Piceance basin at DOE's Multiwell Experiment (MWX) site in Colorado. Topics discussed include geologic data, stress test results, well testing, laboratory core studies, stimulation and stimulation analyses, and postfracture operations.
Regional Geology of the Delaware Basin
Authors: Cook V.O.
Published: December 2007

The Delaware basin of West Texas has a long, complex history and the events that occurred during this great period of time are related to the present economic conditions of West Texas. Geological history in the area presently occupied by the Permian Basin began with gentle tectonic movements and shallow seas during Cambrian and Lower Ordovician time and reached a peak of activity during late Pennsylvanian and early Wolfcampian time. Following this period of pronounced activity, the area became relatively quiet; reefing, along with associated back- and fore-reef deposits, came into prominence. In the Delaware basin vicinity, oil acid gas accumulation has been influenced by the environment of deposition of the rocks comprising the geological column and by tectonic movements that have modified sedimentary framework. Faulting and folding are the principal mechanisms for trapping hydrocarbons in the deeper fields of the basin. Shallow accumulations are often controlled by stratigraphic traps. In addition to a trap, a source of hydrocarbons and presence of rock porosity are necessary for the existence of a reservoir. Gas reservoirs in the Devonian and Ellenburger of the Delaware basin are found primarily in fracture porosity while the Wolfcampian and Pennsylvanian conglomerate reservoirs and middle Permian sand accumulations are characterized by intergranular porosity. The true source of hydrocarbons found in these fields is unknown. Possible sources include origin within the reservoir rock and migration from adjacent shale sections.

Introduction

The Delaware basin of West Texas and southeast New Mexico covers an area about 200 miles long and 100 miles wide. It is a prime example of a large sedimentary basin in which vast amounts Of rock have been deposited. As sedimentary basins in general are important to the petroleum industry of the world, so is the Delaware basin important to the industry of the West Texas-New Mexico area. This prominent geological feature can be expected to attain even greater importance in the future as the quest for oil and gas continues. The growing importance of this significant area is emphasized frequently, especially when the industry notes the ever-increasing number of deep tests announced for the basin and vicinity. The index map of regional structure (Fig. 1) shows the major features that make up the Permian Basin of the southwest United States. The Midland basin on the east and the Delaware basin on the west are separated by the Central basin platform. Both of these basins were areas of deep water during most of Permian time; because of this, they were filled with shales and sandstones deposited in a marine environment. The Central basin platform is an area of Permian reefing that grew over an older structural feature - the West Texas structural platform. South of the Central basin platform is an elongated east-west sedimentary feature called the Sheffield Channel.

JPT

P. 1260ˆ
Determination of Parameters for Individual Layers in Multilayer Reservoirs by Transient Well Tests
Authors: Gao Cheng-tai
Published: December 2007

Approximate expressions for the pressure response and flow rates of individual layers are given when a well produces with a constant production rate from an infinite multilayer reservoir with and without interlayer crossflow. The kh product and skin factor of each layer can be determined by one drawdown test if the common wellbore pressure and the rate of each layer can be measured at the same time. The behavior of the crossflow, caused by skin factors, is discussed. A new method for determining the vertical permeabilities of the shales between layers is developed that uses the crosspoint of the two straight lines of drawdown or buildup curves. This method avoids measuring the wellbore pressures of the producing interval and the closed interval at the same time.
The Preservation of Primary Porosity Through Hydrocarbon Entrapment During Burial
Authors: O'Brien J. J. , Lerche I.
Published: December 2007

We examine the manner in which trapped pore fluids can inhibit sediment compaction during burial and, hence, can enhance primary porosity at depth. In our model studies, we find that primary porosity can be enhanced through fluid entrapment by a factor of two to three at a depth of 30,000 ft [9144 m]. Preservation of porosity is accompanied by the development of an overpressured condition. The magnitude of these effects depends on the pore fluid, its compressibility, the depth at which the reservoir is sealed, the mechanical properties of the rock matrix, and—in the case of a gas reservoir—the thermal gradient. These results indicate that reservoir formations of significant porosity may be preserved to depths greater than 30,000 ft [9144 m] and that, under favorable conditions, it may be possible to identify such formations seismically.
Review of Operational Experience Drilling Wells Through an Underwater Manifold Center
Authors: Hodgson R. K.
Published: December 2007

Drilling techniques required for such developments as the Shell/Esso Central Cormorant development—which is now more than halfway through its drilling and completion phase—differ substantially from normal drilling practices. These differences are reviewed, and the constraints and procedures required to ensure safe and parallel drilling/completion operations in conjunction with the Underwater Manifold Center (UMC) production are explained. Other areas of experience discussed are the weather influence on operations, deviated drilling from a semisubmersible, rig anchoring, and underwater surveillance.
Evacuation of a Residual Oil Pipeline by Inert Gas Displacement
Authors: Webb S. , Bogucz E. , Levy E. , Barrett M. , Snyder C. , Waters C.
Published: December 2007

This paper describes an analysis developed to model the inert gas displacement process for evacuating a high-pour-point oil from a long pipeline. The governing equations were derived from the basic conservation equations for mass, momentum, and energy. The resultant computer program accounts for such effects as pipeline elevation changes, laminar and turbulent oil flow, temperature-dependent oil viscosity, and heat loss from the oil to the ground. Results of computations for an 84-mile [135-km] residual oil pipeline operated by the Pennsylvania Power and Light Co. are presented and compared with pressure measurements obtained during a trial purge of the system. Calculations show that the minimum N2 volume required for a successful pipeline evacuation increases considerably with increased delay time. In addition, theoretical results indicate that for this case, the pipeline purge operation must begin within 20 hours of a shutdown to avoid evacuation difficulties.
Prefracture and Postfracture Formation Evaluation Necessary To Characterize the Three-Dimensional Shape of a Hydraulic Fracture
Authors: Holditch S. A. , Robinson B. M. , Whitehead W. S.
Published: December 2007

In layered, complex, low-permeability gas reservoirs, the problem of excessive fracture-height growth and erratic fracture-growth patterns make fracture-treatment design and evaluation very difficult. In this paper, we describe the importance of collecting and analyzing data before, during, and after a hydraulic-fracture treatment so that the three-dimensional (3D) properties of both the formation and the fracture can be determined.
Mechanisms of Corrosion Inhibitors Used in Acidizing Wells
Authors: Frenier W. W. , Growcock F. B. , Lopp V. R.
Published: December 2007

Two model compounds, n-dodecylpyridinium bromide (n-DDPB) and l-octyn-3-01, were tested in HCI acid as inhibitors for J55 oilfield steel. This paper describes the kinetic and chemical analyses conducted to arrive at inhibition mechanisms for these model compounds. These studies show that the pyridinium forms a weak bond with the chloride-covered surface and is sensitive to temperature and [HCl]. Octynol, however, chemisorbs and produces a film that contains a reaction product of the acetylenic alcohol. This film is quite insensitive to changes in temperature and [HCl]
An Improved Water-in-Oil Emulsion Mud
Authors: Brandt G.W. , Weintritt D.J. , Gray G.R.
Published: December 2007

A water-in-oil emulsion mud free of inert solids has been developed to provide a solution to certain problems associated with drilling, completing and servicing wells. Such invert-emulsion muds are satisfactory for use in wells with temperatures up to 300F and with pressures requiring densities up to 18 lb/gal. The emulsifier used in the preparation of these muds is the mixed salts of fatty acids. It is used in weighted muds in conjunction with a unique organophilic-clay suspending agent. The muds are prepared with ordinary mixing equipment at the wellsite. These muds have been used for drilling through the productive zone, for covering the zone to be perforated or to protect existing perforations during workover operations. Fewer difficulties in servicing wells and in getting wells back on production were experienced when these invert-emulsion muds were used as protective fluids to prevent water or mud from contacting exposed formations.

Qualifications of Invert-Emulsion Muds

An increasing number of wells are being drilled, completed and serviced with oil-base emulsion muds. These water-in-oil emulsions are commonly called "invert emulsions". The amount of water in an oil-base mud may vary from a trace to 60 per cent of the liquid volume of the mud. For purposes of this paper, the primary distinction between an invert-emulsion mud and an oil-base mud is based on whether the water is added as a definite part of the mud composition. In an invert-emulsion mud, the water phase has the important function of imparting controllable properties and characteristics to the mud. The muds described here have been found to have the most satisfactory properties when the water phase constitutes between 20 and 50 per cent of the liquid volume.

In the experimentation and development of a general purpose invert-emulsion mud, certain requirements have gradually evolved.

In the preparation of the mud:the emulsifier should be an easily handled, ground product, free of inert solids;the materials should be readily mixed with conventional rig mixing equipment in no longer time than required for mixing a water-base mud; andthe emulsifier should be effective for fresh and saline waters in a variety of crude and refined oils.
New Developments in Multiple-Well Testing
Authors: Kamal Medhat M. , Hegeman Peter S.
Published: December 2007

Multiple-well tests provide information about reservoir characteristics such as permeability, porosity, communication between wells, and reservoir heterogeneity. A previous paper discussed the state of the art of multiple-well testing. Several developments were reported over the last few years; most are for fractured wells, double-porosity systems, and vertical permeability testing. Several field applications of multiple-well testing were also published during the last few years. This may indicate an increase in the use of multiple-well tests as a result of improvements in our ability to design and to analyze these tests. Much more remains to be done in this area of well testing. This paper discusses the new developments, summarizes the information that can be obtained from multiple-well tests with current technology, and indicates areas for future developments.
Water Imbibition and Characterization of North Sea Chalk Reservoir Surfaces
Authors: Baldwin Bernard A.
Published: December 2007

Water imbibition of a reservoir core was dramatically affected by the removal of small amounts of tightly bound material. Both water-wet and oil-wet chalk cores contained sufficient extractable material to form multimolecular coatings over their entire surfaces. Analysis of the material removed from these reservoir cores provided some clues regarding the fluid dynamics.
Geophysical Workstations in Production Geology
Authors: Nelson H. R. , Bhattacharya G. P. , Tappmeyer D. M. , Jarzabek D. C.
Published: December 2007

Interactive computer graphics systems have been accepted in many exploration and production operations to solve substantial geoscience problems more efficiently and accurately. Examples from several sources will be used to illustrate a few of the interactive solutions available. To illustrate these new developments, this paper introduces the basic components of the interactive environment, reviews the hardware and software system used to produce the examples, describes the interactive interpretational process, and presents the examples with a summary of the geologic problems represented.
Field Histories Show Benefits of Gas and Water-Injection Projects in Eastern Venezuela
Authors: Ramsey L.A.
Published: December 2007

Introduction

Pressure maintenance depletion of appropriate reservoirs by fluid injection has been practiced in Eastern Venezuela since 1948. This program has resulted in benefits such as increased ultimate recovery, lowered artificial-lift costs and, in the case of gas injection, lowered treating costs and the conservation of natural gas which otherwise would be flared.

The L1 sand, OG–56 reservoir, has been under a gas-injection pressure maintenance program since 1948. The oil recovery from this reservoir as of Aug. 31, 1959 had been increased 4.75 per cent over that predicted by natural depletion. This is approximately 6.3 million bbl of additional recovery, with all present outlets still on natural-flow production. The ultimate recovery by this means of depletion is 42 per cent of the original stock-tank oil in place, or 55.9 million STB.

The G sand, 00–271 reservoir, was subjected to a pressure maintenance, water-injection program in May, 1954. As of Aug. 30, 1959, 34.5 per cent of original reserves (or 9.29 million STB of oil) had been produced. This represents an increase of 5.8 per cent, or 1.56 million bbl, over the predicted pressure-depletion recovery.

Gas Injection in L1 Sand, OG–56 Reservoir, Central Oficina Field

Reservoir Characteristics

The L1 sand, OG–56 reservoir, is a north-south trending, fork-shaped channel deposit. The south boundary is defined by the Caris fault, the flanks by sand thinning and the downdip boundary by the water-oil contact at approximately 4,480 ft subsea. The reservoir consists of two segments separated by a shale break which varies from 1 ft to several feet in thickness. The segments are in pressure communication and are considered a single reservoir.

Four of the 82 wells drilled in this sand cored the L1. Some 22 ft of L1 core was recovered and analyzed. The sand ranges from a coarse-grained, well sorted, clean sandstone with high permeabilities and porosities to medium-grained, poorly sorted, silty sandstone with clayey laminations at the top and bottom of the sand. (See Table 1.) The permeability ranges from 300 md in the dirtier sand to 8 darcies in the center portion of the cores. The weighted porosity was found to be 24 per cent.
Evaluation of Steamflood Processes With Horizontal Wells
Authors: Huang W. S. , Hight M. A.
Published: December 2007

Steamflood operations commonly encounter steam override problems. Close well spacing is one method used to reduce this effect. Blind spot areas still exist in the pattern, however, and leave substantial amounts of unrecovered oil after project termination. This study examines the effect of horizontal wells on improving steamflood conformance. A three-dimensional (3D) numerical steamflood simulator was used. The study involves the use of horizontal wells for mature steamfloods to reduce steam override that has already occurred and for prevention of steam override if used at the start of steamflood operations. The data used are from a typical California heavy-oil reservoir.

Simulation indicates that horizontal wells can be effective for reducing or preventing steam override. For a mature 18.5-acre [7.5-ha] pattern, simulated horizontal wells increased ultimate recovery at the end of 11 years from 63.2 to 74.7% of original oil in place (OOIP). When used at the start of steamflood, a pattern of vertical and horizontal wells had a predicted recovery of 72.2% OOIP after only 7 years.
Reservoir Monitoring With the Thermal Multigate Decay Log
Authors: Wyatt D. F. , Smith H. D.
Published: December 2007

The thermal multigate decay (TMD™) logging system, which uses a two-exponential model to isolate borehole and formation Σ effects, can be an effective device for the high-accuracy environment of monitor logging. The minimized influence of borehole parameters on the formation sigma (ΣFmCORR) results in residual oil saturation (ROS) calculations that compare favorably with expected values. The measurement of borehole parameters enables the user to determine whether proper formation flushing has been achieved and whether borehole fluid contamination of perforated intervals presents a potential interpretation problem.

Test pit data and field results indicate that the use of flushing salinities less than approximately 70,000 ppm NaCl can result in significant borehole effects to the observed formation decay rates. The necessary cross section corrections may induce systematic errors into the ROS calculations that are generally larger than any increased statistical uncertainties associated with using a smaller water salinity contrast.
Effect of Oil Composition on Minimum Miscibility Pressure—Part 1: Solubility of Hydrocarbons in Dense CO2
Authors: Silva M. K. , Orr F. M.
Published: December 2007

This paper examines the effect of oil composition on the phase behavior of CO2/hydrocarbon mixtures and, hence, on the development of miscibility in a CO2 flood. Results of component-partitioning measurements are reported for mixtures of CO2 with five synthetic oil systems: normal alkanes, branched alkanes, naphthenes, aromatics, and a mixture of all four molecular types. The results of the experiments indicate that unsubstituted ring structures are less soluble in dense CO2 than branched or normal alkanes with the same number of carbon atoms, but that the addition of alkyl side chains to ring structures improves their solubility. Also reported are component-partitioning measurements for mixtures of CO2 with three crude oils: Rock Creek (paraffinic), Maljamar (more aromatic), and Rock Creek plus 15 wt% of a mixture of aromatic components. The experimental results suggest that of the many factors that influence extraction of hydrocarbons by dense CO2, the distribution of molecular weights present in the oil is the most important.
A New Analytic Model for Fracture-Dominated Reservoirs
Authors: Karasaki Kenzi , Long Jane C.S. , Witherspoon Paul A.
Published: December 2007

A new analytic model for analyzing well test data from fracture-dominated reservoirs is presented. It is a concentric composite model with a finite-radius well located in the center. In the inner region the flow is assumed to be linear, and in the outer region the flow is assumed to be radial. Solutions are obtained analytically and type curves for ranges of dimensionless parameters are presented. The model can be used to find the extent and the flow parameters of the fractures near the well and the average values for the entire system provided that wellbore-storage effects do not mask the early-time data.