bluuebunny/crossref_metadata_2025 huggingface dataset:
Estimating the Coefficient of Inertial Resistance in Fluid Flow Through Porous Media
Authors: Geertsma J.
Published: December 2007

The object of this paper is to introduce an empirical, time-honored relationship between inertia coefficient - frequently misnamed "turbulence factor" - permeability, and porosity, based on a combination of experimental data, dimensional analysis, and other physical considerations. The formula can be used effectively for, among other things, the preliminary evaluation of the number of wells in a new gas field and the spacing between them.

Introduction

It has long been recognized that Darcy's law for single-phase fluid flow through porous media,Equation 1

in which ?=superficial velocity

µ=fluid viscosity

k=formation permeability

p=pressure head,

is approximately correct only in a specific flow regime where the velocity ? is low. Single-phase fluid flow in reservoir rocks is often characterized by conditions in favor of this linearized flow law, but important exceptions do occur. They are in particular related to the surroundings of wells producing at high flow rates such as gas wells.

For the prediction or analysis of the production behavior of such wells it is necessary to apply a more general nonlinear flow law. The appropriate formula was given in 1901 by Forchheimer1; it readsEquation 2

in which ?=density

a=coefficient of viscous flow resistance 1/k

ß=coefficient of inertial flow resistance.

This equation indicates that in single-phase fluid flow through a porous medium two forces counteract the external force simultaneously - namely, viscous and inertial forces - the latter continuously gaining importance as the velocity ? increases. For low flow rates the viscous term dominates, whereas for high flow rates the inertia term does. The upper limit of practical applicability of Darcy's law can best be specified by some "critical value" orf the dimensionless ratio.Equation 3

which has a close resemblance to the Reynolds number. Observe that ß/a has the dimension of a length.

Inertia and Turbulence

As the Reynolds number is commonly used as an indicator for either laminar or turbulent flow conditions, the coefficient ß is often referred to as the turbulence coefficient. However, the phenomenon we are interested in has nothing to do with turbulence. The flow regime of concern is usually fully laminar. The observed departure from Darcy's law is the result of convective accelerations and decelerations of the fluid particles on their way through the pore space. Within the flow range normally experienced in oil and gas reservoirs, including the well's surroundings, energy losses caused by actual turbulence can be safely ignored.
Determination of In-Situ Mobility and Wellbore Impairment From Polymer Injectivity Data (includes associated papers 6412 and 6413 and 6414 and 6415)
Authors: Tinker G.E. , Bowman R.W. , Pope G.A.
Published: December 2007

Polymer injection and filtration field tests being carried out inthe East Coalinga field have been used to determine the degree ofin-situ mobility control and to furnish measurements and determine the nature of wellbore impairment. These tests also have been usedto develop criteria for describing solution quality using polyacrylamideand two grades of biopolymer.

Introduction

Water and polymer field-injection tests are beingconducted to furnish data for a planned pilot projectin the Temblor Zone II reservoir in the East Coalingafield, Calif. The pilot project will evaluate therelative merits of polymer flooding and waterflooding.A waterflood would have an unfavorable mobility ratioof 14.0, but this could be reduced to 1.5 with polymerflooding. Fig. 1 is an index map of the Coalinga fieldshowing the pilot project area.To choose the most suitable polymer for this project, it was necessary to determine the injection characteristicsof both polyacrylamide polymer and biopolymers. Theinjection field tests were supported by field filtrationtests and laboratory studies to define polymer viscosityand filtration properties. The field tests consistedof injecting both polymer solutions and pure water atdifferent times for periods of weeks to generate comparison data for polymer and water for determining thedegree of in-situ mobility control and possible wellboreimpairment.

Polyacrylamide Injectivity Test

Polyacrylamide polymer (Pusher 700) was originallyselected for field testing at the Coalinga field because, at the time of the test, more was known about thispolymer. To achieve maximum mobility control usingpolyacrylamide, and because it was readily available, afresh-water (300-ppm NACI) source was developed forthe project. This water caused severe wellbore damage (20-fold decrease in permeability) from clay swellingand dispersion during initial water-injection testing;therefore, the test well was chemically treated with theDarley treatment to prevent this damage.The properties of the unconsolidated sand and thefluids involved with the tests are as follows:

Property Hx Sand Jv Sand Dept, ft 1,660 1,750Thickness ft 8 17Permeability, md 470 230water at Sor, md 165 80Porosity 0.28 0.28Oil gravity, deg.API 20 20 20Reservoirtemperature, deg.F 100 100Oil viscosityat reservoirtemperature, cp 25.0 25.0Water viscosityat reservoirtemperature, cp 0.64 0.64

The injection system for the polyacrylamide testwas carefully designed to prevent mechanical shear oroxygen degradation of the polymer at the surface. Fig.2 is a plot of water and polymer injectivity vs cumulative injection.

JPT

P. 586^
High Strength Granular Sealing Material Increases Efficiency of Primary Cementing and Squeeze Cementing
Authors: Einarsen Charles A.
Published: December 2007

The use of high strength granular materials in cement slurries has proved beneficial for cementing casing and squeeze cementing operations in Permian in Basin oil and gas wells. The addition of 1 to 4 lb of ground walnut shells to each sack of cement made possible successful high column cementing jobs in fields where high fill-ups normally cannot be obtained because of lost circulation. In squeeze cementing operations the number of cementing stages required for shutting off water was reduced by the addition of walnut shells to the last 50 per cent of the volume of cement slurry.

Introduction

The high hydrostatic head, created in the annulus when cementing casing, frequently is the cause of loss of slurry into weak formations or formations containing fractures or vugs. Common precautions taken to reduce this loss are reducing the density of the slurry adding effective sealing agents to the slurry, or both. One phase of this paper concerns the use of high strength granular sealing materials in cement slurry to seal openings into formations so that the slurry may be pumped to the desired level behind the casing. In squeeze cementing operations neat cement often fails to effect a complete seal because of the tendency of the slurry to enter only the weakest zones. This is indicated by the number of stages frequently required to stop the flow of water or gas. The intrusion of cement slurry into each perforation in a water or gas producing zone is probably necessary to eliminate flow completely, and a high final squeeze pressure may be a means of assuring entry of cement into each perforation or zone of weakness. The second phase of this paper concerns the use of high strength granular materials in cement slurries to obtain a high final squeeze pressure.
Big Muddy Water Flood
Authors: Haller R.W.
Published: December 2007

This paper presents a summary of the production and waterflood history of the Second Wall Creek Reservoir in the Big Muddy field. This highly successful Eastern Wyoming water flood has doubled the production from the Wall Creek in less than two years of operation. An outline of the laboratory and reservoir studies which culminated in the installation of a pilot water flood in 1953 is presented. Pertinent reservoir data, such as oil and water saturations, are given. The development program and current production practices of the waterflood program are also presented. The primary and waterflood performance is shown for several individual wells and for the entire flood. Cumulative waterflood recoveries and the estimated ultimate recoveries are given, in conjunction with the current development and operating costs and the future economics of the waterflood program.

Introduction

The Big Muddy oil field is located about 4 miles west of Glenrock in Converse County, Wyo. The field was discovered in 1916, although Wall Creek production was not encountered until 1917, when State 10 Lease Well No. 1 was brought in flowing at a rate of 150 BOPD. This discovery touched off a prolific drilling program and brought about one of Wyoming's famous oil booms. Most of the wells drilled to the Wall Creek were located along the crest of the structure and were generally spaced on a 10-acre pattern as shown in Fig. 1. Full development of acreage did not take place on leases located on the flanks of the structure. However, lease line drilling was sufficient to prove up this peripheral area. The majority of wells were drilled with cable tools to the top of the sand. Casing was then run and the wells tailed in to a depth 50 to 60 ft below the sand top. A typical casing program consists of 40 ft of 20 in. surface pipe, 250 ft of 15 1/2 in. pipe to seal off a good water sand, 1,000 ft of 12 1/2 in. pipe to combat hole cavings and finally 3,000 ft of 6 1/4 in. casing set on top of the sand. There is little record of cementing having been done in the early wells.
The Effect of Linear Pressure Trends on Interference Tests
Authors: Kamal Medhat
Published: December 2007

In analyzing the results of an interference test, the pressure change at the observation well usually is regarded pressure change at the observation well usually is regarded as the effect of the producing wells only. The existence of any other trend in the reservoir pressure will cause errors in the values of the reservoir properties deduced from the interference test unless the effect of this pressure trend is considered in the analysis of the test results. One of the important advantages of pulse testing over the conventional interference test is that the pulse test response can be detected easily from unknown trends in the reservoir pressure.

The purpose of this article is to show the effect of a linear pressure trend on interference tests. The physical reservoir considered in this study is an infinite, homogeneous, isotropic, porous medium of uniform thickness filled with a single-phase fluid that has a small and constant compressibility and a constant viscosity. The porosity and permeability of the porous medium are assumed to be independent of pressure. The porous medium are assumed to be independent of pressure. The flow of the fluid through the porous medium is assumed to be isothermal radial flow into or out of a well open over the entire thickness of the porous medium. The pressure gradient is assumed to be small and the gravity forces are assumed to be negligible.

Injection of q STB/D was started in a well at time t=0 and the pressure response was recorded at the observation well. The pressure at the observation well as a function of time can be represented by Eq. 1(1)...

or, in dimensionless form.,(2)...

where,(3)...(4)...

The dimensionless pressure at the observation well was calculated for values of dimensionless time ranging from 0 to 3. This range was used because that is the time required to run a pulse test on a reservoir with average properties. The dimensionless pressure at the observation well also was calculated assuming that there were several linear trends in the reservoir pressure in addition to the effect of the injection of q STB/D in another well. Different slopes were used for the linear pressure trend. These slopes were chosen such that the change in the dimensionless pressure ranged from 10 to 30 percent. The results of these calculations are shown below.

The errors in analyzing the results of the interference tests, errors caused by the existence of the linear trends in the reservoir pressure, were found by matching the type curves that resulted in each case with the type curve of the pressure response at the observation well in absence of linear trends in the reservoir pressure. Fig. 1 shows this match for the case of a 30 percent change in pressure.

P. 1383
Compressibility Factors for CO2-Methane Mixtures
Authors: Simon R. , Fesmire C.J. , Dicharry R.M. , Vorhis F.H.
Published: December 2007

Compressibility factors from a high-ratio CO2-natural gas mixture are compared with other experimental data and values calculated using two correlations. Discussion includes the use of these factors in monitoring reservoir performance for the SACROC Unit CO2 injection project.

Introduction

The SACROC Unit CO2 injection project in Scurry County, Tex., required transporting 200 Mcf/D of CO2 for 200 miles. A feasibility study of the mode of transportation resulted in selection of a "supercritical-pressure-state" pipeline system.

A study was made of available data on compressibility (z) factors for CO2-natural gas at supercritical pressures, as well as of two engineering calculation methods. This study indicated that the z factors should be measured rather than taken from published information.

This paper compares our measured compressibility factors with calculated and published compressibility data, and describes applications of z factors to the various phases of the SACROC Unit CO2 injection project. phases of the SACROC Unit CO2 injection project. Experimental PVT Data

There were two reasons for measuring z factors rather than relying on published information:Reamer et al.'s data for the CO2-methane system did not include C2+, which is contained in the pipeline gas.For engineering purposes, corresponding-state and equation-of-state calculation methods are not accurate enough near the critical point. CO2 pipeline design conditions include the critical point.

Our measurements were made in a visual PVT cell using the CO2-natural gas mixture described in Table 1. Conditions ranged from 680 to 3,001 psia and 49 to 120 degrees F. Tables 2 and 3 and Fig. 1 show the experimental results along with the calculated values and Reamer et al.'s data.

Experimental Method

The gas used for the compressibility-factor measurements was prepared from pure compounds. It was analyzed by determining the CO2 in an Orsat apparatus (thus removing the CO2) and chromatographing the re-reminder of the gas.

The liquid-vapor, two-phase boundary of the gas was estimated, and the gas pressure was kept above the cricondenbar to insure single-phase transfer from a storage vessel to the visual PVT cell.

In the visual cell, the pressure was decreased in steps and the volume was measured at each step. This pressure-volume relation was determined at 49, 70, 90, and pressure-volume relation was determined at 49, 70, 90, and 120 degrees F. At 49 and 70 degrees F we observed bubble points and a dew point. Compressibility factors were points and a dew point. Compressibility factors were calculated from the pressure, volume, and temperature values (z = pV/RT).

Experimental Results

Table 1 shows the analysis of the gas used, along with the measured specific gravity and volumetric expansion values. Table 2 shows the measured z factors for the four temperatures. These data are plotted in Fig. 2 with the observed bubble and dew points.

JPT

P. 81
A Flowmeter for Measuring Subsurface Flow Rates
Authors: Newman J.L. , Waddell C. , Sauder H.L.
Published: December 2007

An instrument capable of measuring subsurface flow rates is described. The instrument is self-contained and may be run on piano wire line. It detects flow by means of an impeller suspended between two torsion wires. The force of the well fluid striking the impeller causes the impeller to rotate, exerting a torsional force to the wires. This force is determined by recording the angle of rotation of the impeller on film using a battery-driven, clock-controlled camera. The impeller is sensitive to flow in either direction and the same instrument can be used to measure injection as well as production rates. Changes in direction of flow, such as might be caused by thief zones, are measurable and are indicated by a reversal of the direction of rotation of the impeller. Adjustment of the sensitivity of the instrument to measure a wide range of flow rates is accomplished by the use of different size torsion wires. An umbrella-type fluid trap, which contacts the casing or wellbore, diverts the flow through the flow tube. The fluid trap remains closed while running in the hole and can be opened at any point in the well. The instrument with the trap closed is 1¾ in. OD and may be run through 2 in. tubing. Successful flow profiles have been made on wells with flow rates ranging from 60 B/D to 4,000 B/D at surface pressure up to 4,500 psi. The instrument is designed for high-pressure and high-temperature operations.

Introduction

The need for an instrument that will measure flow rates in a wellbore is as old as reservoir engineering itself. A number of such devices have been designed within the past few years. Some of these have been described in the literature. One of these devices, a hot-wire anemometer type, made many successful jobs in dry gas producing areas. Difficulty was encountered when this flowmeter was used in wells producing liquids and development work was initiated to overcome this difficulty. The present flowmeter is the result of this work and provides an instrument with a wider range of application in the industry.
Simulating Residual Saturation and Relative Permeability in Heterogeneous Formations
Authors: Paterson Lincoln , Painter Scott , Zhang Xiaodong , Pinczewski W. V.
Published: December 2007

Network models are used to investigate the effect of correlated heterogeneity on capillary dominated displacements in porous media. Residual saturations and relative permeabilities are shown to be sensitive to the degree of correlation and anisotropy. The network models reproduce the experimental observation that relative permeability is greater in the direction parallel to the bedding compared with perpendicular to the bedding. The scatter commonly observed in core measurements of residual saturation may be attributed to the presence of correlated heterogeneity in actual reservoir rocks.
Improved Two-Phase Model for Hydraulic Jet Pumps
Authors: Noronha F. A. F. , França F. A. , Alhanati F. J. S.
Published: December 2007

A new model is proposed to predict the performance of hydraulic jet pumps (HJP's) when pumping two-phase gas-liquid mixtures. The model performance is compared with the models of Petrie et al.1 and Jiao et al.2; input data were the measurements taken by Jiao3 when testing an industrial HJP.

The present model results from the application of the one-dimensional conservation law of mass, momentum, and energy to the gas-liquid flow throughout the HJP. It differs from the previous published ones because it takes into account the flow of the two-phase compressible homogeneous mixture along the different parts of the device. It is not just an adaptation of a model originally developed for single-phase flows. Until now, most models representing the flow of a gas-liquid mixture in an HJP were adapted from models developed for incompressible single-phase flows. The gas compressibility, for instance, is fully considered, as was done by Cunningham4 when modeling a jet pump driven by a gas.

The solution of the proposed model requires the knowledge of two constant energy dissipation factors, i.e., flow inside the nozzle and flow inside the throat. The best values for these factors were obtained by performing a regression analysis over the data of Jiao.3 The results showed a consistently better agreement, over the full range of the operational variables, with the experimental data than those delivered by the existing models.
Stimulation for Methane-Gas Recovery From Coal
Authors: Jeffrey R. G. , Wold M. B. , Choi S. K. , Settari Antonin
Published: December 2007

During the past several years, a combination of data from field and laboratory experiments, published data from commercial treatments, and concurrent analysis and model development activities has led to a better understanding of the processes occurring in coal during stimulation operations. At the same time, better modeling capabilities have been developed. For example, a new hydraulic fracture design model that includes pressure-dependent nonlinear leakoff, multiple interacting fractures, and failure in the coal near the fracture plane as a result of changes in effective stress is being developed and is being used to study fracture propagation in coal. In addition, two- and three-dimensional (2D and 3D) discrete element and hybrid finite element models that couple the mechanical and multiphase fluid response of the coal have been applied to analyzing problems arising from cavity completion operations.

In this paper, we compare data obtained from field trials in coal seams with model simulations, and we discuss the implications for stimulation design and execution.
Disproportionate Permeability Reduction Is Not a Panacea
Authors: Stavland Arne , Ekrann Steinar , Hettervik K. O. , Jakobsen S. R. , Schmidt Terje , Schilling Birgitte
Published: December 2007

In this paper, we discuss experimental and theoretical studies on the effects of disproportionate permeability reduction (DPR) (i.e., the ability to reduce relative permeability to water more than to oil). The theoretical part discusses DPR effects by simple analytical arguments, supported by simulations. DPR causes buildup of water saturation in the treated zone to accommodate the water/oil ratio, Fwo, delivered by the reservoir. Core flooding experiments were also carried out, with a DPR gel placed in one half of the core. There is excellent agreement between theory and core flooding results. It was observed that the water saturation in the treated zone increased. Saturation profiles were measured with a CT scanner and is well matched by simulation.
Fast Procedure for Upscaling Compositional Simulation
Authors: Christie M. A. , Clifford P. J.
Published: December 2007

Single-phase upscaling techniques have been in use for a number of years now to incorporate subgrid reservoir description information into reservoir simulation. There have also been a number of approaches to developing two-phase upscaling algorithms suitable for black oil simulation.

The key barrier to the development of compositional upscaling techniques is algorithm speed. A straightforward extension of existing two-phase upscaling approaches would consume enormous amounts of computer time because of the number of additional components modeled and the need to perform flash calculations.

This paper describes an upscaling method for simulations in which compositional processes play a key role, such as miscible gas injection or gas cycling schemes. We will describe the method to generate upscaled compositional fluxes in two or three dimensions, and the way in which the upscaled fluxes are incorporated into a compositional simulator.

Our approach uses a streamline technique, which provides a tremendous gain in speed for the loss of a small amount of accuracy. The streamline technique produces upscaled fluxes almost identical to those obtained from postprocessing conventional compositional model runs in a fraction of the time.

The results of applying these upscaled fluxes in a realistic example show that we can obtain close agreement between fine and coarse grid models of lean gas injection into oil at residual saturation. For an example problem with a 12-component equation of state (EOS), the component recovery curves with upscaled fluxes on a 5 × 5 grid agree well with the original 100 × 20 fine grid
Predicting Natural or Induced Fracture Azimuths From Shear-Wave Anisotropy
Authors: De G. S. , Winterstein D. F. , Johnson S. J. , Higgs W. G. , Xiao H.
Published: December 2007

Prediction of fracture orientation to determine depletion geometry is a key step in reservoir characterization and development optimization. Wireline crossed-dipole anisotropy logs measure shear-wave velocity anisotropy and provide a relatively inexpensive alternative to tiltmeter surveys and nine-component vertical seismic profiles (9C VSP's) for such predictions. A multiwell study in Cymric oil field, California, was conducted to map the variations in the predicted azimuth of induced fractures in a shallow Miocene siliceous shale reservoir (>500 millions of barrels of oil in place). Results from anisotropy data showed that the azimuths predicted by anisotropy logs and VSP's agreed. The agreement is significant because these two technologies measure very different kinds of seismic waves and have scales of investigation differing by two orders of magnitude. Within the productive zone, the predicted fracture azimuths from anisotropy data differed by about 60° from the regional stress in the NW portion of the Cymric development, while they were approximately aligned with the regional stress in the SE portion. Marked changes in azimuth also occurred as a function of depth across a regional Plio-Miocene (P-M) unconformity.

Independent evidence, including observed steam breakthrough, natural fracture azimuths, and curvature analysis, supports the azimuths predicted from anisotropy data. Time-lapse temperature data from observation wells in a pilot steamflood showed anisotropy in horizontal permeability. Microresistivity borehole imaging logs allowed measurements of borehole breakouts and large, open natural fractures. The curvature analysis indicated a NW trending region of high curvature in the NW part of the Cymric structure.

The large changes in azimuth with both depth and location in the development area show that regional stress maps are inadequate for planning oilfield development when stress patterns are complex, especially when deviated wells or induced fracturing are planned. Local stress configurations, therefore, must also be determined.
Analysis of Surface and Wellbore Hydraulics Provides Key to Efficient Blowout Control
Authors: Oudeman Pieter
Published: December 2007

Assessment of blowout rate and composition is a key issue for decisions concerning blowout control method, design of kill operations, determination of direct (e.g., environmental) and indirect (loss of reserves) damage, etc. Usually, loss of control over the outflow of the well implies that the blowout rate cannot be established with conventional means. Experience shows that, because of the large reservoir decompression, production well performance cannot be extrapolated reliably to blowout conditions. Hence, surface (simple) observations, such as wellhead/drillpipe pressure and temperature, effluent shape and size and noise field, results of previous kill attempts, and pressure response of nearby wells have to be interpreted in terms of the blowout rate. This paper presents two examples of blowouts for which the combination of such data led to a consistent and accurate picture of blowout well performance; it also describes how such estimates contributed to decisions concerning the kill strategy, leading to success in a relatively short time.
A Review of Zechstein Drilling Issues
Authors: Williamson M. D. , Murray S. J. , Hamilton T. A. P. , Copland M. A.
Published: December 2007

A number of issues can arise when drilling through Zechstein formations that have a bearing on the health and safety of personnel, as well as on the time to complete operations and final well costs. Operational problems present some intrinsic hazard or safety risk. Additionally, the procedures applied to alleviate these problems also present a safety risk, as they are usually nonroutine and unfamiliar, thus increasing the likelihood of errors.

In this paper, the operational issues, their causative mechanisms, and alleviation procedures are introduced and categorized. Decision analysis is applied to each of the operational issues, for both the well planning stage and for the drillsite, which relates the well responses to the causative mechanism and, therefore, to the selection of the most appropriate alleviation procedure.
Field Cases of Cost-Efficient Slickline Well Interventions
Authors: Larimore D. R. , Fehrmann G. Z.
Published: December 2007

The comparison of today's slickline capabilities with its early usage for routine remedial workovers and maintenance best illustrates the significant advances that have occurred within slickline technology. Today, for example, slickline can be used to set and retrieve slickline-retrievable safety valves or plugs; open and close downhole circulating devices; retrieve accurate depth/time data for correlation with memory production surveys for well diagnostics (problem identification), reservoir description, or flow analysis; provide accurate correlation of tubing casing collars; and pull and run multiple flow controls, set packers, and other downhole equipment without explosives, set monobore tools, and perform other well interventions that are dependent on measurement accuracy. This expansion is overwhelming when considering that less than a decade ago slickline was considered only for mechanical well workovers.

This paper discusses the newly developed technology that allows slickline to economically provide alternatives economically to services that were traditionally reserved for more costly options. Case histories illustrate the enlarged scope of services and how the equipment combines to provide the innovative low cost service options that the industry has been seeking.
Effect of No-Flow Boundaries on Viscous Fingering in Porous Media of Large Aspect Ratio
Authors: Yang Zhengming , Yortsos Yanis C.
Published: December 2007

We report on a boundary effect associated with the preferential propagation of viscous fingers along no-flow boundaries in miscible displacements in two-dimensional (2D) rectilinear geometries near conditions of transverse equilibrium (TE) (large values of the generalized aspect ratio RL). It is shown that this effect intensifies with an increase in the mobility ratio, and diminishes with increased permeability disorder, and as the system departs from conditions of TE. The effect disappears altogether if periodic boundary conditions are used. We show that this effect results from the violation of the no-slip condition at no-flow boundaries, associated with Darcy's law. It must be considered in simulations of viscous fingering in relatively homogeneous media, near conditions of TE, particularly when gravity segregation occurs.
New Results on Decline Curves Considering Non-Darcy Flow Effects
Authors: Camacho-V. R. G. , Vásquez-C. M. A. , Padilla-S. R.
Published: December 2007

Most theoretical work on decline curves considering nonlaminar flow is related to dry gas systems. The purpose of this study is to analyze decline curves considering non-Darcy flow effects in the reservoir for both slightly compressible liquid flow and solution gas-drive systems, keeping the wellbore pressure constant.

The transient and boundary-dominated flow periods are examined by means of a finite difference black-oil reservoir simulator with a variable bubblepoint formulation. The consequences of this formulation under non-Darcy flow are also investigated.

The influence of the mechanical skin factor on the rate response is also documented. For the case of liquid flow, presented for the first time, it is an expression to evaluate the total skin factor, which is a function of the mechanical skin and skin caused by inertial forces. This expression is given in terms of physical properties of the system, and it is proportional to the square root of the pressure drop. It also equals the square root of the Reynolds number. This is one of the main findings of this work.

The possible presence of a semilogarithmic straight line of reciprocal rate for both liquid and solution gas-drive systems is investigated, and new insights are provided. In general, when inertial effects are important and the bottomhole wellbore pressure is kept constant, a true semilogarithmic straight line of the inverse of oil rate does not develop. This result is valid for both liquid and solution gas-drive systems, and it is an important difference in the case of liquid flow under a constant oil rate production, where a semilog straight line of the pressure drop is evident during the transient period considering a large drainage area.

For liquid flow, an apparent straight line may be fitted, and the ordinate to the origin is approximately equal to the value of total skin computed with the expression mentioned previously.

The presence of inertial effects distorts the shape of the laminar decline curves for both multiphase and slightly compressible liquid flow, causing type curve analysis to yield wrong estimates of the wellbore and reservoir parameters. Also, to perform a history match with data affected by non-Darcy flow by use of a conventional simulator that uses Darcy's law in its formulation, an alteration of the reservoir properties is necessary.
Field-Test Results of a Three-Phase Holdup Measurement in Horizontal Wells With a Pulsed-Neutron Source
Authors: Roscoe B. A.
Published: December 2007

A new method of obtaining three-phase holdup (oil/water/gas) information in horizontal wells has been field tested. The method uses the data available from a pulsed-neutron tool. This measurement uses the inelastic near/far countrate ratio in addition to the near and far carbon/oxygen (C/O) ratios. The inelastic near/far countrate ratio response is dominated by gas in the borehole, whereas the near and far C/O ratios are used to separate the water and oil contributions of the borehole and formation. By using a linear programming approach, this information is combined to produce quantitative three-phase holdup answers. Calibration ofthe measurement is achieved by the combined use of laboratory measurements and Monte Carlo modeling predictions.

To obtain independent verification of the three-phase holdup answer, a local probe tool was run in combination with the pulsedneutron tool. The local probe tool is sensitive to two phases (water and hydrocarbon) and, hence, can be used for a partial verification of results. Field-test results show good agreement between the two independent measurements under various conditions of gas, oil, and water holdup in the horizontal borehole.
Athabasca Oil Sands
Authors: Bellows L.A. , Bohme V.E.
Published: December 2007

Introduction

The Athabasca oil sands of the McMurray formation in northeastern Alberta cover an area of about 21,000 sq miles and contain the world's largest reserve of economically recoverable oil. Fort McMurray, a small town in the heart of the oil-sands area, is about 235 air miles northeast of Edmonton. A railway serves the town but no year-round roads connect with the rest of Alberta (Fig. 1).The McMurray formation is of early Cretaceous age, deposited unconformably on a limestone surface of Devonian age. The sediments appear to have originated from the Canadian Shield to the east and were deposited in bays and deltas of large fresh-water lakes. The lakes were later replaced by marine seas in which the overlying Clearwater shale was deposited (Fig. 2).The sand body rarely exceeds 200 ft in thickness and is made up of innumerable minor and major lenses of unconsolidated oil-bearing sand interspersed with clay and shale partings of variable thickness, carbonaceous and lignite beds, some rock and boulders. Overburden thins along a topographic trough which contains the Athabasca River and increases in thickness to about 2,000 ft along the southern and western limits of the oil impregnation. Oil sand is exposed on the banks of the Athabasca River and its tributaries.

The oil sand is primarily quartz with varying percentages of silt and clay. Maximum oil saturation is about 18 percent by weight in a clean sand but decreases with increasing silt and clay content. Sand with oil saturation in excess of about 10 per cent is classed as a "good" grade while sand containing less than about 5 per cent of oil is not considered to be economically recoverable by present mining and processing techniques.The oil found in the McMurray formation is heavy, viscous and sulfurous. Specific gravity is from 1.002 to 1.027; viscosity, 3,000 to 400,000 poise at 60F. The sulfur content is from 4 to 5 per cent, and the nitrogen content is about 0.4 per cent.

JPT

P. 479^
The Importance of Interfacial Tension on Fluid Distribution During Depressurization
Authors: Mackay E. J. , Henderson G. D. , Tehrani D. H. , Danesh A.
Published: December 2007

Many North Sea reservoirs produce water at very high cuts under current waterflooding conditions. As oil production drops below economical limits, procedures for recovering residual and bypassed oil are being investigated. One technique identified as potentially suitable for at least ten candidate fields in the United Kingdom Continental Shelf (UKCS) is to depressurize these fields. During pressure depletion, improved hydrocarbon recovery has been shown to result from the release of solution gas and subsequent expansion of the freed gas. The precise nature of gas nucleation and its subsequent growth phenomena, however, have not been well understood. For example, there exists experimental evidence supporting two apparently conflicting models describing gas nucleation.

High pressure micromodel studies have shed light on the physical processes occurring at the pore scale during pressure depletion in waterflooded systems. Specifically, tests performed with fluids characterized by different gas/oil interfacial tensions (IFT's) have shown the important role gas/oil and gas/water IFT's play during bubble formation and growth in porous media. Analysis of visual information from water-wet micromodel tests have shown that the magnitude of the liquid-gas IFT is one of the factors that determines in which phase the bubbles nucleate, and how many bubbles form per unit volume of pore space. A low gas/oil IFT results in a relatively large number of bubbles forming in the oil phase only, with little or no supersaturation. Higher values of gas/oil IFT result in increasing levels of supersaturation with relatively fewer bubbles nucleating at cavity sites on the water-solid interface. Not only is the gas/oil IFT at the bubblepoint important in determining the nucleation loci and densities, but the increasing gas/oil IFT values with decreasing pressure also affect the distribution of the three phases during the process. Increasing gas/oil IFT's, combined with the effect of disjoining pressure in thin water films separating oil ganglia, result in delayed oil production and expulsion of water from the system below a certain threshold pressure. This suggests that there is an identifiable minimum pressure below which hydrocarbon production will not be viable.
Development and Application of the Multiwell Productivity Index (MPI)
Authors: Valkó P. P. , Doublet L. E. , Blasingame T. A.
Published: December 2007

In this article we generalize the concept of the pseudosteady-state productivity index for the case of multiple wells producing from or injecting into a closed rectangular reservoir of constant thickness. The work complements the analytical study by Rodríguez and Cinco-Ley1 for systems produced at constant flowing pressures. Wells are represented by fully penetrating vertical line sources located arbitrarily in a homogeneous and isotropic reservoir. The multiwell productivity index (MPI) is a square matrix of dimension n, where n is the number of wells. The MPI provides a simple, reasonably accurate and fast analytical tool to evaluate well performance without dividing the cluster into single-well drainage areas. The MPI approach is used to obtain approximate analytical solutions for constant (but possibly different) wellbore flowing pressures, and to visualize the resulting pressure field. In addition, the skin factor trace technique is introduced as a tool to monitor a cluster of wells. The MPI technique is illustrated using a synthetic example taken from Ref. 2, as well as two field cases.
Extending Predictive Capabilities to Network Models
Authors: Øren P.-E. , Bakke Stig , Arntzen O. J.
Published: December 2007

We reconstruct three-dimensional (3D) sandstone models that give a realistic description of the complex pore space observed in actual sandstones. The reconstructed pore space is transformed into a pore network that is used as input to a two-phase network model. The model simulates primary drainage and water injection on the basis of a physical scenario for wettability changes at the pore level. We derive general relationships among pore structure, wettability, and capillary pressure for the different pore level displacement mechanisms that may occur in the network model.

We present predicted transport properties for three different reconstructed sandstones of increasing complexity: Fontainebleau, a water-wet Bentheimer, and a mixed-wet reservoir rock. Predicted transport properties are in good agreement with available experimental data. For the reservoir rock, both the experiments and the simulated results show that continuous oil films allow low oil saturations to be reached during forced water injection. However, the oil relative permeability is very low.
High-Resolution Reservoir Models Integrating Multiple-Well Production Data
Authors: Wen Xian-Huan , Deutsch C. V. , Cullick A. S.
Published: December 2007

This paper presents a method to generate maps of high resolution permeability from multiple well single-phase flow rate and pressure data. The dynamic (i.e., temporal) production data contain important information about the interwell permeability distribution that should be integrated with static data, such as well and seismic data, to generate reservoir models to provide reliable input to reservoir simulation and reservoir management. A two-step procedure is proposed for such data integration: establish the spatial constraints on large-scale permeability trends caused by the production data by means of an inverse technique and construct the detailed geostatistical reservoir models subject to those spatial constraints by means of geostatistical techniques. The single-phase pressure and production data could be provided by permanent pressure gauges, simultaneous multiple well tests, or flow rates under primary depletion.

Production data and reservoir petrophysical properties, specifically permeability, are nonlinearly related through flow equations. Establishing the spatial constraints on permeability resulting from production data calls for the solution of a difficult inverse problem. This paper adapts the sequential self-calibration (SSC) inverse technique to single-phase multiple-well transient pressure and production rate data. The SSC method is an iterative geostatistically based inverse method coupled with an optimization procedure that generates a series of coarse grid two-dimensional (2D) permeability realizations whose numerical flow simulations correctly reproduce the production data. Inverse results with two synthetic data sets show that this SSC implementation is flexible, computationally efficient, and robust.

Fine-scale models generated by downscaling the SSC generated coarse-scale models (by simulated annealing) are shown to preserve the match to the production data at the coarse scale. Finally, reservoir performance prediction results show how the integration of production data can dramatically improve the accuracy of production forecasting with significantly less uncertainty.
An Investigation of Fluid Leakoff Phenomena by Use of a High-Pressure Simulator
Authors: Lord D. L. , Vinod P. S. , Shah S. N. , Bishop M. L.
Published: December 2007

This paper describes the results of fluid-loss tests conducted with various hydraulic fracturing fluids through the use of a large-scale, high-temperature, high-pressure simulator (HPS) that has several unique capabilities. Among these capabilities is the ability to perform dynamic fluid-loss experiments over a large surface area under 1,000 psi differential pressure. Nearly all fluid-loss studies previously reported in the literature have described laboratory tests involving small-core plugs with a surface area of approximately 1.7 in.2. In contrast, the fluid-loss data collected in the HPS are over a significantly larger surface area, approximately 606 in.2.

Results from the HPS were compared to laboratory data, and significant differences in spurt-loss values were found. Surface texture was also found to be a significant factor in determining the extent of filter cake formation. The paper provides insight into the differences between fluid-loss control mechanisms displayed by linear polymer solutions and crosslinked gels. Experiments specifically designed to evaluate various hypotheses were performed to determine the significance of external filter cake on fluid-loss control of crosslinked fluids. Conventional fracturing fluids and additives were found to be inefficient in controlling fluid loss to natural fractures in a rock matrix.
Sizing Gelant Treatments in Hydraulically Fractured Production Wells
Authors: Seright R. S. , Liang J. , Seldal Mailin
Published: December 2007

Often, when production wells are stimulated by hydraulic fracturing, the fracture unintentionally breaks into water zones causing substantially increased water production. To correct this problem, we developed an engineering basis for designing and sizing gelant treatments in hydraulically fractured production wells. In these treatments, gelant penetrates a short distance from the fracture face into the porous rock associated with both water and hydrocarbon zones. Success for a given treatment requires that the gel reduce permeability to water much more than that to hydrocarbon. We present a simple 11-step procedure for sizing these gelant treatments. This procedure was incorporated in user-friendly graphicaluser-interface software that can be downloaded from our web site at http://baervan.nmt.edu/ResSweepEffic/reservoir.htm.