bluuebunny/crossref_metadata_2025 huggingface dataset:
A Blotter-Type Electrolytic Model Determination of Areal Sweeps in Oil Recovery by In-Situ Combustion
Authors: Ramey H.J. , Nabor G.W.
Published: December 2007

A blotter-type electrolytic model was utilized to prepare flow diagrams for a field test of the in-situ combustion process. It is pointed out that the areal sweep of a combustion pattern is similar to sweep patterns that would be developed at an infinite mobility ratio, which exists (approximately) across a combustion front because of the complete removal of liquids from the sand behind it.

The precision of the blotter method was tested by comparison with results obtained by other techniques and was found to be satisfactory. The blotter-type model will not furnish as much information as more elaborate and expensive potentiometric models, but its speed of operation and ease of construction make it a highly satisfactory tool to determine areal sweep patterns. A tabulation of sweep efficiency and mobility ratio is furnished for various well geometries.

Introduction

In connection with the first field experiment with the in-situ combustion method of oil recovery: flow diagrams for the unique well geometry and boundary conditions involved in the subject test were developed. From these diagrams, information concerning the areal sweep and distribution of flow was obtained. A survey of the literature on potentiometric models, utilized to solve two-dimensional flow problems, indicated that the' information desired could be obtained by means of a blotter-type model by making certain modifications in the technique. The following discussion describes the application of the modified blotter-type electrolytic model to the solution of the problem of the flow of gases in an oil reservoir for an engineering appraisal of the progress of the combustion front during the first field experiment.

Theory

Considerable information has been published on the theoretical aspects of electrical model techniques. One author stated that:

"The models are based on the observation that since the velocity of an ion in an electrolytic system is proportional to the potential gradient, just as the velocity of a fluid particle in a porous medium is proportional to the pressure gradient, the paths of the ions in the electrolytic systems must be similar to those of the fluid particles in a porous medium with the same geometry and equivalent boundary conditions."

This suggestion of a real analogy has been established repeatedly by comparisons of analytic derivations with model results.
Fracture Width and Embedment Testing in Soft Reservoir Sandstone
Authors: Lacy L. L. , Rickards A. R. , Bilden D. M.
Published: December 2007

A new computer-controlled laboratory technique has been developed to measure propped fracture width and embedment in weakly consolidated cores or unconsolidated sands under simulated downhole conditions. Previously, laboratory studies on cores had determined embedment in hard rocks where embedment was normally limited to 50% of the proppant grain diameter. Several studies also indicated the importance of embedment with one monolayer or less of proppant coverage. The effects of water saturation and fracture-fluid filtrate on formation softness and embedment have not been previously published. Consequently, the objectives of the current paper are to extend previous research results to include soft, weakly consolidated cores and unconsolidated sands with multiple proppant layers. The influence of water saturation and dynamic fluid leakoff on embedment are also shown to be important.

The current investigations indicate that embedment becomes a problem when the Brinell hardness (BH) of the formation is less than about 20 kg/mm2 or when the static Young's modulus of formations cores is less than about 2 million psi (13 GPa). Embedment has been determined for cores with static Young's moduli between 0.1 and 1.4 million psi (0.7 to 9.6 GPa). In soft and wet sandstone, embedment can reduce fracture width up to 60% or more for proppant concentrations of 2 lbm/ft2. For unconsolidated sands, embedment is influenced by fracturing-fluid type, water saturation, and downhole conditions. Cyclic loading conditions associated with well shut-ins also increase embedment in unconsolidated sands. This paper reviews and discusses test data on formation cores from south Texas, New Mexico, the North Sea, and the Gulf of Mexico. Most of the commercial fracture-design programs neglect embedment problems in calculating fracture width, while other fracture simulators contain allowances for embedment.
A Further Note on Pulse-Test Interpretation
Authors: Startzman R.A.
Published: December 2007

The development of pulse testing, a special type of well interference testing, has resulted in interpretation techniques that require the use of graphical methods. These methods make use of such variables as "time lag" and "pressure response", obtained visually from plots of well pressure vs time. Such methods require that the pulse-rate schedule be a symmetric, rectangular step-function of constant frequency and amplitude.

In actual field practice it may be impossible to maintain a pulse-rate schedule of this type. Furthermore, even if such a schedule could be adhered to, the resulting pressure signal in the responding well might possess a high degree of random noise. Noise caused, perhaps, by a low-resolution pressure instrument can obscure the test results so that time lag and pressure response cannot be determined accurately.

A more general approach that overcomes these difficulties is that of automatically history-matching observed responding well pressures with pressures computed from a mathematical model. A convenient method is to minimize the least-squares objective function

(1)

Any obvious long-term reservoir pressure trends must be removed from the measured pressures in order to arrive at po. An analysis of the residuals, (pt - po), computed at the minimum of psi, will determine if pressure trends have been successfully removed.

Since pt and its first and second derivatives can be determined analytically from the exponential integral solution to the diffusion equation, a useful minimization technique is the Newton-Raphson method. This method is used to solve the following equations for transmissibility, T, and storage, s:

(2)

and

(3)

This interpretation technique was programmed in FORTRAN for the IBM 360/50. The Newton-Raphson method was found to be quite satisfactory and most problems took less than 10 seconds for adequate convergence.

P. 1143ˆ
Field Examples of Ultrasonically Enhanced Density, Neutron-Porosity, and Caliper Logs Obtained While Drilling
Authors: Schultz W. E. , Moake G. L. , Jackson C. E.
Published: December 2007

Density, photoelectric factor (Pe), and neutron-porosity measurements made while drilling are extremely sensitive to the distance between the sensors and the borehole wall (standoff). To minimize these effects, an ultrasonic transducer is positioned collinearly with the nuclear sensors. Rapid pulsing of the transducer provides frequent measurements of the standoff. These measurements are used to average the nuclear data in a manner that emphasizes the smallest standoff data. This greatly improves the quality of the density, Pe, and neutron-porosity logs. Additionally, the standoff measurements are used to correct the neutron log for residual standoff effects. Measurements from the standoff transducer are also combined with those from two other ultrasonic transducers to obtain a high-resolution caliper log. Besides providing useful borehole information, the caliper readings are used to correct the nuclear measurements for hole-size effects. This new technology is illustrated with log examples from a variety of wells. One of the examples illustrates the effectiveness of an enhanced-vertical-resolution processing technique in identifying thin beds.
Estimation of Lithofacies Proportions by Use of Well and Well-Test Data
Authors: Hu L. Y. , Blanc Georges , Noetinger Benoit
Published: December 2007

A crucial step of the two commonly used geostatistical methods for modeling heterogeneous reservoirs, sequential indicator simulation and truncated Gaussian simulation, is the estimation of the lithofacies local proportion (or probability density) functions. Well-test-derived permeabilities show good correlation with lithofacies proportions around wells. Integrating well and well-test data in estimating lithofacies proportions could permit the building of more realistic models of reservoir heterogeneity. This integration is difficult, however, because of the different natures and measurement scales of these two types of data.

This paper presents a two-step approach to integrating well and well-test data into heterogeneous reservoir modeling. First, we estimate lithofacies proportions in well-test investigation areas with a new kriging algorithm called KISCA. KISCA consists of kriging jointly the proportions of all lithofacies in a well-test investigation area so that the corresponding well-test-derived permeability is respected through a weighted power-averaging of lithofacies permeabilities. For multiple well tests, an iterative process is used in KISCA to account for their interaction. After this, the estimated proportions are combined with lithofacies indicators at wells for estimating proportion (or probability density) functions over the entire reservoir field with a classical kriging method.

We considered some numerical examples to test the proposed method for estimating lithofacies proportions. In addition, we generated a synthetic lithofacies reservoir model and performed a well-test simulation. The comparison between the experimental and estimated proportions in the well-test investigation area demonstrates the validity of the proposed method.
Reservoir Fracture Mapping Using Microearthquakes: Two Oilfield Case Studies
Authors: Phillips W. S. , Rutledge J. T. , Fairbanks T. D. , Gardner T. L. , Miller M. E. , Maher B. S.
Published: December 2007

Patterns of microearthquakes detected downhole defined fracture orientation and extent in the Austin chalk, Giddings field, Texas, and in the 76 field, Clinton County, Kentucky. At two sites in the Austin chalk we detected more than 480 and 770 microearthquakes, respectively, during hydraulic stimulation, and more than 3,200 during primary production in Clinton County. The data were of high enough quality that 20%, 31%, and 53% of the events could be located, respectively.

Reflected-wave data constrained microearthquake locations to the stimulated depths at the base of the Austin chalk. In plan view, microearthquakes defined elongate fracture zones extending from the stimulation wells parallel to the regional fracture trend. However, the widths of the stimulated zones differed by a factor of five between the two Austin chalk sites, suggesting a large difference in the population of ancillary fractures. Post-stimulation production was much higher from the wider zone.

In Clinton County, microearthquakes defined low-angle, reverse-fault fracture zones above and below a producing zone. Associations with depleted production intervals indicated that the mapped fractures had been drained previously. Drilling showed that the fractures currently contain brine. The seismic behavior was consistent with stress changes associated with poroelastic effects above and below a drained volume or with the mass exchange of brine replacing produced oil.
Permeability Reduction by Pyrobitumen, Mineralization, and Stress Along Large Natural Fractures in Sandstones at 18,300-ft Depth: Destruction of a Reservoir
Authors: Lorenz J. C. , Billingsley R. L. , Evans L. W.
Published: December 2007

Gas production from the Frontier formation at 18,300-ft depth in the Frewen Deep #4 well, eastern Green River basin (Wyoming), was uneconomic despite the presence of three sets of numerous, partially open, vertical natural fractures. Production dropped from 360 Mcf/ D to 140 Mcf/D during a 10-day production test, and the well was abandoned. Examination of the fractures in the core suggests several possible reasons for this poor production. One factor is the presence of mineralization in the fractures. Another more important factor is that the remnant porosity left in the fractures by partial mineralization is commonly plugged with an overmature hydrocarbon residue (pyrobitumen). Reorientation of the in-situ horizontal compressive stress to a trend normal to the main fractures, which now acts to close fracture apertures during reservoir drawdown, is also an important factor.
Re-Engineering Simulation: Managing Complexity and Complexification in Reservoir Projects
Authors: Saleri N. G.
Published: December 2007

Managing complexity and technological complexification is a necessity in today's business environment. This paper outlines a method to increase value addition significantly by multidisciplinary reservoir studies. In this context, value addition refers to a positive impact on a business decision. The approach ensures a level of complexification in line both with business questions at hand and the realities of reservoirs.

Sparse well control, seismic uncertainties, imperfect geologic models, time constraints, software viruses, and computing hardware limitations represent some common reservoir realities. The process model detailed in the paper uses these apparent shortcomings to moderate (i.e., guide) the level of complexification. Several project examples illustrate the implementation of the process model. The paper is an extension of three previous investigations1–3 that deal with issues of method and uncertainty in reservoir-performance forecasting.
Gas Hydrates of Hydrogen Sulfide-Methane Mixtures
Authors: Noaker Leslie J. , Katz Donald L.
Published: December 2007

Experimental data are presented for hydrate formation conditions for mixtures of hydrogen sulfide and methane. Vapor-solid equilibrium constants for hydrogen sulfide are also presented. Equilibrium constants, defined here as the ratio of the mole fraction of hydrogen sulfide in the vapor phase (dry basis) to the mole fraction of hydrogen sulfide in the solid phase (dry basis), were calculated using the vapor-solid equilibrium constants for methane presented in an earlier paper. The conditions at which a natural gas will form gas hydrates with water may be computed from its composition, when hydrogen sulfide is present in addition to carbon dioxide and the paraffin hydrocarbons.

Introduction

Many gases are known to form solid hydrates in the presence of liquid water at temperatures above 32°F. This hydrate formation is of importance to the natural gas industry inasmuch as most of the constituents found in natural gases will form hydrates. The attention of the industry was called to hydrates by Hammerschmidt in 1934. A number of papers have been written giving the temperatures and pressures at which these hydrates will form and a bibliography on the subject has been compiled. Deaton and Frost report work for various pure gases and for some natural gases. Katz and co-workers have reported data for various gases at high pressure. They developed a method of predicting conditions for hydrate formation from equilibrium constants and from gas gravity. The effects of anti-freeze agents on the formation of hydrogen sulfide hydrate were reported by Bond and Nelson. The hydrogen sulfide-water system, including hydrate, has been the subject of recent investigation by Sage and co-workers.

Mixtures of hydrates behave as solid solutions and an equilibrium exists between the vapor phase and the solid phase that appears to be comparable to the equilibrium between vapor and liquid phases. By means of the vapor-solid equilibrium constants which have been published for methane, ethane, propane, isobutane, and carbon dioxide it is possible to determine the temperature and pressure at which hydrates will form for a specific gas mixture when water is present.
Effective Transmissibilities of a Gridblock by Upscaling — Comparison of Direct Methods with Renormalization
Authors: Peaceman Donald W.
Published: December 2007

Previous methods for upscaling fine-scale permeability data for use in reservoir simulation produce effective permeabilities for each simulator gridblock. Since transmissibilities between neighboring gridblocks are required by the simulator, it is better to determine six "half-block transmissibilities" for each gridblock. These can be calculated directly by solving the finite-difference equations for pressure in each of six half-blocks, wherein uniform pressures are applied at two opposite faces and no-flow conditions are applied at the other four faces.

Alternatively, in order to reduce computation time, renormalization has been proposed for calculating effective permeabilities of the gridblocks. These previous proposals ignore anisotropy and require that the elemental blocks and each coarse block be rectangular. In this paper, renormalization is modified to avoid these disadvantages.

Renormalization is most easily implemented if there are N × N × N elemental blocks within each coarse block, where N is a power of 2. A more flexible variation of renormalization is also presented which reduces this restriction somewhat. However, the direct method is much more flexible with regard to the number of elemental blocks in each direction.

While renormalization might be expected to be faster than the direct method, comparison of running times shows that a highly efficient iterative solver for the direct method is somewhat faster than renormalization.
Thermodynamic Micellization Model for Asphaltene Aggregation and Precipitation in Petroleum Fluids
Authors: Pan Huanquan , Firoozabadi Abbas
Published: December 2007

A thermodynamic framework is proposed to describe the structure of asphaltene micelles and precipitation in crude. The asphaltene micelle is assumed to consist of an asphaltene core surrounded by a solvated shell. The shell contains both resin and all the other species except asphaltenes. The theoretical framework consists of the standard Gibbs free energy of micellar formation and the Gibbs free energies ofthe petroleum liquid and the precipitated phase. The standard Gibbs free energy of the micellar formation is modeled as the sum of various contributions including the association between asphaltene molecules in the core, the deformation of asphaltene and resin molecules in the micelle, and the adsorption of resin molecules onto the micellar core. The Gibbs free energy ofthe petroleum liquid phase includes the contributions from the standard state, mixing, and interactions among the species. The precipitated phase is assumed to be an ideal solid mixture of asphaltenes and resin.

The direct minimization of the Gibbs free energy of the liquid/solid system is invoked to calculate the micellar structure and composition in crude and the amount and composition of the precipitated phase. The predicted results reveal that the addition of diluents n-C5 to n-C10 leads to asphaltene precipitation; whereas diluents such as C2 or C3 give rise to precipitation of nearly all resin and asphaltenes from crude. These predictions are in agreement with laboratory measurements. The predicted micellar size increases with dilution ratio. This prediction is also in agreement with measured data.
Material Balance for a Bottom-Water-Drive Gas Reservoir
Authors: Dumore J.M.
Published: December 2007

A material balance is developed for a gas reservoir in which the rising gas/water contact remains horizontal. The time-integrated cumulative water influx is introduced, which for numerical computations is sometimes more advantageous than the van Everdingen and Hurst integral. On the basis of the equations developed, material balance calculations of the history of an actual gas field are carried out to calculate the water influx. The strength of the estimated radial, limited aquifer, which must supply the water for the influx, is determined. It appears that the strength decreases with time and asymptotically approaches a limiting value. (Some possible reasons for this decrease are mentioned.) If we take the strength as constant and equal to the limiting value, however, very small deviations from the past pressures occur. With the same value for the strength of the aquifer, the future behavior of the gas reservoir is computed, assuming constant gas production rate and no water production.

Introduction

For a depletion-type gas reservoir - i.e., when there is no water encroachment - the average gas pressure is a function of the cumulative production pressure is a function of the cumulative production and can easily be calculated from a material balance. For a gas reservoir bounded by an aquifer, the average gas pressure also depends on the water influx, which in turn depends on the rate of pressure decline and thus on the production rate. In this case the material balance is much more complicated. In the following we have developed the material balance of a bottom-water-drive gas reservoir, in which the rising gas/water contact remains horizontal. In a numerical example, the equations are applied to an actual gas field in Northwest Germany.
A Modified Two-Phase Well-Control Model and Its Computer Applications as a Training and Educational Tool
Authors: Choe Jonggeun , Juvkam-Wold Hans C.
Published: December 2007

This paper presents a modified two-phase well-control model to simulate two-phase kick behavior after comparing a dynamic two- phase well-control model and a single-phase model. The model is reliable and easy to simulate without any of the numerical problems that might occur in a dynamic two-phase model. The simulator calculates gas influx rate from the formation assuming an infinite-acting reservoir.

The paper also introduces computer applications for IBM-compatible personal computers for use as a well-control training and educational tool. The simulator has enhanced graphical presentations with random access for all menus and options by use of a computer mouse. The simulator is written in Visual Basic™3.

The simulator can handle vertical wells, directional wells, extended-reach wells, and horizontal wells with two different buildup rates for onshore or offshore wells. The simulator also provides the theoretical kill sheet for any selected well geometry. The simulator is a user-interactive well-control program with an automatic wellcontrol option. It demonstrates the basic concepts of well control and shows the pressure and volume responses of the kick with time.
Complex Multiphase Equilibrium Calculations by Direct Minimization of Gibbs Free Energy by Use of Simulated Annealing
Authors: Pan Huanquan , Firoozabadi Abbas
Published: December 2007

The computational problems in reservoir fluid systems are mainly in the critical region and in liquid-liquid (LL), vapor-liquid-liquid (VLL), and higher-phase equilibria. The conventional methods to perform phase-equilibrium calculations with the equality of chemical potentials cannot guarantee a correct solution.

In this study, we propose a simple method to calculate the equilibrium state by direct minimization of the Gibbs free energy of the system at constant temperature and pressure. We use the simulated annealing (SA) algorithm to perform the global minimization. Estimates of key parameters of the SA algorithm are also made for phase-behavior calculations. Several examples, including (1) VL equilibria in the critical region, (2) VLL equilibria for reservoir fluid systems, (3) VLL equilibria for an H2S-containing mixture, and (4) VL-multisolid equilibria for reservoir fluids, show the reliability of the method.
A Low-Tension Waterflooding Process
Authors: Foster W.R.
Published: December 2007

A field test to examine some aspects of surfactant behavior, and a later polymer injection study, led to the conclusion that a tertiary oil bank can polymer injection study, led to the conclusion that a tertiary oil bank can be formed in a reservoir using low-tension surfactants. Another conclusion is that it is essential to control the mobility immediately behind the bank to insure that a significant fraction of the mobilized oil will be driven to the producing wells.

Introduction

The work summarized here represents a part of the effort by Mobil Research and Development Corp. to develop an economic low-tension waterflooding process. Various aspects of displacement at low tension process. Various aspects of displacement at low tension are discussed in general terms. Details of the extensive background effort supporting the necessary laboratory and field experiments, an interpretation of results, and the development of an adequate transport theory are deferred to later publications. Not all aspects of this process have been field tested yet. However, Mobil has carried out a field test in South Texas to examine factors relating primarily to surfactant behavior. A polymer injection study was conducted at the same site some time later. As a result of these field studies and supporting theory we conducted that a tertiary oil bank can be fanned in a reservoir using low-tension surfactants and that mobility control immediately behind the bank is essential to insure that a significant fraction of the "mobilized oil" will be driven to producing wells. A surfactant waterflooding process capable of producing a tertiary oil bank has also been described by producing a tertiary oil bank has also been described by Gogarty and Tosch. One significant difference between their "Maraflood" process and the process described here is the manner in which the surfactant is used. Maraflood employs a surfactant slug that is miscible with the reservoir crude. Miscibility implies zero interfacial tension between this slug and the reservoir crude oil. Achieving and, particularly, maintaining this miscibility condition places rigorous requirements on the composition of the slug. Our process, on the other hand, does not depend upon process, on the other hand, does not depend upon miscibility between crude oil and water, but relies on very low interfacial tension between a water solution/ dispersion of a surfactant and the reservoir crude oil. Also, the compositional requirements that must be met in order to achieve and maintain a condition of very low tension are somewhat different from those needed in the Maraflood process.
Solving Engineering Problems With PC-Based Relational Databases
Authors: Bastian P. A. , Pietsch C. L. , Voneiff G. W.
Published: December 2007

Information management and instant access to information is increasingly important in the day-to-day operation of oil and gas fields, and the data are only as valuable as our ability to use them to solve problems. This paper presents an example of a project-driven approach to engineering information management of large engineering projects, such as integrated reservoir studies. By project-driven, we mean that the design and content of the database are project-specific and custom-built to fit the needs of the project. This approach has the advantage of addressing the specific requirements of a particular project and providing the end users of that database with a customized interface to access the data. We used a PC-based relational database management system (RDBMS) to custom build a database from existing engineering data as part of a larger integrated study. The data were originally in a variety of formats. The RDBMS allowed us to construct rapidly a database specific to the needs of the project. The database includes forms and reports for data entry and review and graphics for displaying data. In addition, the database is very flexible, allowing changes to be made quickly and easily as the project progresses or if the objectives of the project change along the way. Finally, the database can import a wide variety of raw-data formats and export data to other engineering analysis applications.
Development of a Modified Pressure Interference Equation
Authors: Prasad Raj K.
Published: December 2007

The equations presented in previous literature on well interference are adequate when there has been no pressure interference at the observation well prior to pressure interference at the observation well prior to shut-in. However, tests made during the later stages of the development of a reservoir frequently reveal that this interference has occurred. A modified equation is developed here to account for it. Pressure at a closed-in observation well, due to continued oil production at off set wells, is given by:

.........(1)

where

aj = distance from jth well to the observationwell ftPws = pressure at the observation well at t hoursof shut-in, psiapi = initial pressure of the reservoir, psiaq = production rate at the observation well priorto shut-in, RB/Dqj = production rate at the jth interfering well, RB/Dtj = total production time elapsed at jth wellprior to shut-in of the observation well, hourstj = producing time of the jth well at the time ofpressure observation after shut-in of theobservation well, hoursNw = total number of interfering wells. CC = ----------0.00105k162.6qm = -----------kh

When t is very small compared with tj,

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

or when tj + tj is very small,

,.....(3)

Eq. 1 can be written as

...........(4)

A plot of pws vs on semilogarythmic paper for small t should yield a straight line of slope m =

162.6 and an intercept defined by

...........(5)

Substituting the value of pi from Eq. 5 into Eq. 1 yields.

P. 149
The Use of Source and Green's Functions in Solving Unsteady-Flow Problems in Reservoirs
Authors: Gringarten Alain C. , Ramey Henry J.
Published: December 2007

Although it is an old method, the use of Green's functions to solve unsteady flow problems in reservoir engineering is not widely practiced. The reason is that it is difficult to find the appropriate Green's junction. In this study, tables of instantaneous Green's and source functions were prepared that can be used with the Newman's prepared that can be used with the Newman's product method to generate solutions for a wide product method to generate solutions for a wide variety of reservoir flow problems. New solutions for infinite conductivity sources were also prepared.

Introduction

The transient flow of a slightly compressible fluid in a homogeneous and anisotropic porous medium D, bounded by a surface Se (Fig. 1), is described by the diffusivity equational derived from the continuity equation and Darcy's law? Assuming constant permeabilities, porosity, and fluid viscosity and small pressure gradients everywhere, and neglecting the effect of gravity, the diffusivity equation can be written as

Equation (1)

where x, y and z are the principal axes of permeability, and the coefficients Nx, Ny, Nz are permeability, and the coefficients Nx, Ny, Nz are the principal diffusivities. When Nx = Ny = Nr (cylindrical systems), the diffusivity equation can be written as

Equation (2)

The diffusivity constants are given by

Equation (3)

Many techniques have been used for solving Eqs. 1 and 2. Most of these were first used for solving heat conduction problems and have since been applied by different authors to petroleum engineering. In the literature, most problems were solved either with Laplace transforms or Fourier transforms. One useful method employs Lord Kelvin's instantaneous point source solution. Another method that is of value although very rarely used is the Green's function method. This study presents the point source solution as part of a more general theory of Green's functions. part of a more general theory of Green's functions. This theory is applied in combination with other techniques to yield immediate solutions to difficult flow problems, some of which either have not been published or have been solved by long analytical published or have been solved by long analytical methods or sophisticated numerical techniques only.
A Tertiary COFCAW Pilot Test In the Sloss Field, Nebraska
Authors: Parrish David R. , Pollock Charles B. , Ness N.L. , Craig F.F.
Published: December 2007

The operability of COFCAW in previously waterflooded reservoirs was demonstrated by the production of 80,000 barrels of oil from a 40-acre five-spot. This thermal recovery pilot was unusual in several respects. The pay was thin and deep, the oil was light, and the viscosity was low.

Introduction

The purpose of this paper is to describe a pilot test of COFCAW in a previously waterflooded portion of the Sloss Field, Nebraska.The Sloss pilot was one of a series of COFCAW field tests conducted in several reservoirs of differing types. This field test program is the subject of a separate paper.The COFCAW pilot at Sloss was not carried to completion but was replaced by a full-scale project. The expanded COFCAW project is the subject of another separate paper.The decision to expand COFCAW operations at Sloss was based partly on the encouraging results of the pilot and largely on an urgent need for a full-scale evaluation of this tertiary oil recovery method.

The Sloss Field

The Sloss field, with about 38 million bbl of oil originally in place is one of the larger fields in the Denver basin. It is near the city of Kimball, in Kimball County, Nebr.The field was discovered in Nov. 1954. By mid-1958, when primary operations ended, there were 89 wells in the field, most of them on 40-acre spacing. Additional wells completed later brought the total number to slightly more than 100.The field produces a light (38.8 deg. API) paraffinic oil from a stratigraphic trap in well consolidated Muddy "J" sandstone. There are two main reservoirs -- the J1 at a depth of about 6,200 ft and the slightly deeper J2. In some areas, the two reservoirs are separated by only a few feet of shale. Much of our discussion will be confined to the J1 reservoir (Fig. 1), since only that reservoir was involved in the COFCAW operations.

Production History Production History Early performance was typical of volumetric reservoirs. Peak production of 9,600 BOPD occurred in mid-1957, about 21/2 years after discovery. By 1958 the reservoir pressure had declined from the original pressure of 1,328 psia to less than 400 psia, well pressure of 1,328 psia to less than 400 psia, well below the bubble-point pressure of 689 psia. About 11 percent of the original oil in place was recovered percent of the original oil in place was recovered during pressure depletion operations.The field was unitized with Amoco Production Co. as operator and a waterflood was started in mid 1958. Response to the waterflood was good, and a maximum incremental oil producing rate of about 3,000 BOPD over the estimated primary rate was obtained. By the start of the COFCAW pilot project in mid-1963, most of the reservoir had been waterflooded. (For a description of the COFCAW process, see Ref. 1 and its references.)

JPT

P. 667
Pore Level Modeling of the Effects of Wettability
Authors: Blunt Martin J.
Published: December 2007

We describe a network model to study the effects of wettability which is based on the pore level scenario of Kovscek et al.1 The network model simulates primary drainage, water injection and oil re-injection. The portions of the rock surface contacted by oil after primary drainage can become oil-wet. Water remains in the corners of the pore space and these sections remain water-wet. During forced water injection, oil layers can become sandwiched between water in the corners and water in the center of the pore space. These layers maintain continuity of the oil phase and allow low oil saturations to be achieved during forced water injection. However, the flow rates through them are very low.

We investigate models with different fractions of oil-wet pores, contact angles and initial water saturations. We present relative permeabilities, recovery curves and capillary pressures and interpret the results in terms of the behavior at the pore scale. The residual oil saturation, Sor, shows a non-monotonic dependence on wettability. In many cases weakly water-wet and moderately oil-wet systems have a lower Sor than either strongly water-wet or strongly oil-wet systems. Weakly oil-wet media may have a high Sor, and low relative permeabilities to both oil and water.
A Low Cost Method of Production Stimulation
Authors: Garst A.W.
Published: December 2007

A simple treatment has been developed by which water-block is removed from oil wells by lowering oil-water interfacial tension to a very low value.

The treatment is made by injecting a crude oil solution of a carefully selected surface-active agent into the water-blocked formation. From 1,000 to 4,000 gals. of crude oil containing 1 per cent surface active agent is used. Shut-in time following treatment is usually from 12 to 24 hours.

The treatment has been used in 90 wells with successful results obtained in 39 wells representing seven formations in nine fields. The successful treatments have resulted in added productivity of 1,217 BOPD. Treatment cost is unusually low, compared with other types of well treatments and workovers normally done for improvement of productivity.

Introduction

The Problem

Although water-block removal has received considerable attention in the past, there has remained a need for an inexpensive, effective remedial treatment for water-blocked wells. This paper discusses the development of a remedial treatment utilizing a surface active agent which has shown considerable ability to increase production rates from wells in which some water-blocking was known or suspected to exist.

The need for a remedial treatment to remove waterblock has been most clearly observed when established producing wells have shown marked productivity loss following exposure of the producing formations to water during workover operations involving water-base muds and cement. The need for such a treatment has not been so clearly evident in acidized wells. Partial water-block in such wells may occur undetected because of the complexity of operations and particularly when such wells are capable of making a maximum allowable after workover. Field tests reported in this paper show that the incidence of such water-blocking may be fairly high in at least one formation previously subjected to acidization.
High-Pressure Drilling
Authors: Maurer William C. , Heilhecker Joe K. , Love William W.
Published: December 2007

A series of full-scale field drilling tests has shown that high-pressure bits operating at pressures of 10,000 to 15,000 psi can drill many formations two to three times faster than can conventional bits. High-pressure drills can effect significant savings where drilling costs are high, such as in deep land wells, in arctic areas, and offshore.

Introduction

A survey has been made of more than 25 novel drills, and drilling rates were predicted for each of these drills in oil wells on the basis of available laboratory drilling data. Novel drills that thermally spall rock were found to have limited potential for drilling oil wells because most sedimentary rocks will not spall. Devices such as lasers and electron beams had extrapolated drilling rates of less than 1 ft/hr because of the high energy requirement for fusing rock. Extrapolated laboratory data indicated that high-pressure erosion bits operating at pressures of 10,000 to 20,000 psi should drill medium-strength rocks at rates of 70 to 280 ft/hr compared with 30 to 170 ft/hr for conventional roller bits. As a result of this study, research was begun to further evaluate high-pressure bits for oil-well drilling.

Earlier Work

A series of laboratory tests was conducted on high-pressure drilling before the full-scale field tests were begun. In all tests, water was used as the drilling fluid.

Pulsed-Jet Experiments Pulsed-Jet Experiments After the literature was surveyed, an An-ny surplus cannon (Fig. 1) was modified to fire water pulses at pressures up to 25,000 psi. The diameters of holes pressures up to 25,000 psi. The diameters of holes eroded using 0.2 to 1-in.-diameter nozzles were three to four times larger than the nozzle diameters (Fig. 2). At 25,000 psi, a 1.45-gal water pulse was fired through a 1.0-in.-diameter nozzle in 0.02 second. This water jet drilled a 3.9-in.-diameter X 3/4 -in. deep hole in Indiana limestone, which corresponds to an instantaneous drilling rate of 1 1,000 ft/hr and a hydraulic power output of 70,000 hp. These tests demonstrated that a threshold pressure must be exceeded before fluid jets will drill; Fig. 3 shows that this threshold pressure was about 6,200 psi for Indiana limestone. psi for Indiana limestone. The amount of energy required to remove rock was determined by measuring the amount of energy expended and the amount of rock removed during each water pulse. The data from these tests indicated that a 3,000-hp jet bit would drill an 8-in.-diameter hole in Indiana limestone at rates of 280 to 370 ft/hr.

Laboratory High-Pressure Drilling Test

After the pulsed-jet tests were completed, a fracturing truck was used to pump water through a 2-in. diameter high-pressure drill (Fig. 4) at pressures up to 13,500 psi. The first bit had two 0.15-in.-diameter nozzles (nozzle area = 0.035 sq in.) and was designed to operate at pressures up to 10,000 psi. As the pressure across this bit was increased to 10,000 psi, the flow rate increased to 133 gal/min and the power output across the bit increased to 780 hydraulic horsepower (hhp).

JPT

P. 851
Oil Displacement by Foams in Relation to Their Physical Properties in Porous Media
Authors: Minssieux L.
Published: December 2007

An investigation was conducted on the leading properties of water-gas foams and on their circulation in porous media. Results were interpreted by using the concept of the quality, or gas content, of foams in circulation. The quality is found to correlate with the foam viscosity as determined by Darcy's law in a given section of the porous medium.

Introduction

The use of water-gas foams has been developed in recent years in the field of oil and gas production. Because of their specific properties, foams have found a variety of uses. Some examples follow:

1. The well known use of foam as an aerated drilling fluid has been extended to workover and remedial well operations. Such light fluids are especially suitable for operating in decompressed reservoirs where traditional types of mud might cause damage.

2. The technology of exploiting underground gas storage reservoirs is also involved. Foams have been used to even out the gas injection profile in the case of stratified formations. They have also been suggested as a way of preventing gas leakage through the cap rock of storage reservoirs.

3. Attempts have been made to use foams as a secondary recovery fluid, although this practice is still quite limited.

4. More recently, such fluids have been used as a means of treating wells to reduce water or gas inflow during oil production. Tests of this technique have been carried out on Soviet fields.

These divers possible uses of foams take advantage of their varied properties and also take into account their behavior in porous media. This is the point in particular that we shall deal with here. particular that we shall deal with here.

Characteristic Properties of Foams

The water foams considered here may be defined as relatively stable and homogeneous dispersions of gas in a foaming-agent solution containing 0.1 to 1.0 percent of a surfactant. percent of a surfactant.

The simple aspect of such fluids (see Fig. 1) shows that the two phases that make them up are more of less associated with one another to form a structure that becomes more and more orderly as the proportion of gas becomes higher. proportion of gas becomes higher.
Optimum Sand Concentrations in Well Treatments
Authors: Dehlinger Peter , Browne W.H. , Bundrant C.O.
Published: December 2007

Brief laboratory investigations are described which attempt to determine optimum sand concentrations in gel-sand and oil-sand well-treatments. The investigations apply to the case where sand acts as a propping agent in formation fractures. Both analytically and experimentally it is demonstrated that optimum sand concentrations can be defined. It is difficult to translate laboratory results to field treatments, however, since the relative distribution of sand and fluid in fractures may not be the same as injected. This is because fluid may penetrate the furtherest narrow portions of fractures, which would not pass sand. Optimum concentration of a monolayer of Ottawa sand in fractures of 0.025-in. width at the usual range of pressures encountered in treatments appears to be about ½ to 2 lb/ gal. of gel.

An investigation of abrasion of rock-walls by sand in treatments, described in the Appendix, shows that such abrasion is not probable in significant amounts.

Introduction

Experience in the Spraberry formation of West Texas, as well as in other formations, has shown that sand is a necessary and vital part of gel-sand and oil-sand treatments. Many observers of treatments have also concluded that there seems to be an optimum range of sand concentration for these injections. Brief laboratory investigations were made at Battelle Memorial Institute to study flow in fractures with different sand concentrations. To investigate the existence and range of optimum concentrations in the laboratory, however, necessitates knowledge of the mechanism by which the sand aids in increasing subsequent production.

The action of sand in fractures is usually thought to be either that of a propping agent, thus providing a greater effective formation permeability; that of an abrasive in eroding fill material in fractures; or that of an abrasive eroding rock-wall irregularities along fracture surfaces. Investigations described in the Appendix show that sand does not appear to erode rock-wall materials appreciably. In a subsequent paper it is reasoned, at least for the Spraberry formation of West Texas, that the primary action of sand is not in removing fill materials in fractures. In this formation, and probably others, too, the main effect of sand appears to be that of a propping agent.