bluuebunny/crossref_metadata_2025 huggingface dataset:
Neural Network Approach Predicts U.S. Natural Gas Production
Authors: Al-Fattah S. M. , Startzman R. A.
Published: December 2007

The industrial and residential market for natural gas produced in the United States has become increasingly significant. Within the past 10 years, the wellhead value of produced natural gas has rivaled and sometimes exceeded the value of crude oil. Forecasting natural gas supply is an economically important and challenging endeavor. This paper presents a new approach to predict natural gas production for the United States with an artificial neural network (NN).

We developed an NN model to forecast the U.S. natural gas supply to 2020. Our results indicate that the U.S. will maintain its 1999 production of natural gas until 2001, after which production increases. The network model indicates that natural gas production will increase by an average rate of 0.5%/yr from 2002 to 2012. This increase will more than double from 2013 to 2020.

The NN was developed with a large initial pool of input parameters. The input pool included exploratory, drilling, production, and econometric data. Preprocessing the input data involved normalization and functional transformation. Dimension-reduction techniques and sensitivity analysis of input variables were used to reduce redundant and unimportant input parameters and to simplify the NN. The remaining parameters included data from gas exploratory wells, oil/gas exploratory wells, oil exploratory wells, gas depletion rate, proved reserves, gas wellhead prices, and growth rate of the gross domestic product. The three-layer NN was successfully trained with yearly data from 1950 to 1989 using the quick-propagation learning algorithm. The NN's target output is the production rate of natural gas. The agreement between predicted and actual production rates was excellent. A test set not used to train the network and containing data from 1990 to 1998 was used to verify and validate the network prediction performance. Analysis of the test results showed that the NN approach provides an excellent match with actual gas production data. An econometric approach, called stochastic modeling or time-series analysis, was used to develop forecasting models for NN input parameters. A comparison of forecasts between this study and another is presented.

The NN model has use as a short-term as well as a long-term predictive tool for natural gas supply. The model can also be used to quantitatively examine the effects of the various physical and economic factors on future gas production.
Productivity Determination and Pump Resizing Using Variable-Speed Electric Submersible Pumps
Authors: Kelley Robert S.
Published: December 2007

This paper discusses a variable-speed electric submersible pump system usedas a tool to provide productivity information for resizing electricsubmersible pumps. Use of this equipment enabled the generation ofproductivity information without having to pull the existing downholeequipment. Field results using this method are presented.

Introduction

Waterflood expansion and developmental drillingprograms are being pursued actively in the LostSoldier Tensleep reservoir in central Wyoming. Response to the increased injection has resulted infrequent resizing to larger artificial lift equipment.As new injection wells are drilled and existing wellsconverted to injection to complete the pattern flood, adjacent areas are experiencing significant increasesin static and operating bottomhole pressures. Tohandle the increased fluid withdrawals possible, themajority of producing wells are being changed frombeam to electric submersible pump (ESP) lift andexisting ESP's are being resized.

The production of ESP-pumped wells in the LostSoldier Tensleep reservoir ranges from 400 to 6,200BFPD (64 to 986 m3/d fluid). Average depth of the reservoir is 5,000 ft (1524 m). Producing-wellbottomhole temperature is approximately 175 degreesF (79 degrees C).ESP lift plays an important role in this reservoir.At the end of 1978, 31 well, or 61% of all producing wells, were on ESP lift. These wells account for 87%of the total fluid produced. During the year therewere 10 new ESP installations and 14 ESP installationsthat were resized. It has been found thattraditional methods of predicting productivitycharacteristics for ESP sizing cannot be used in allcases. Several different size installations have beenrequired in some wells before an acceptable operatingfluid level has been achieved.

As a solution to reducing the uncertainty in sizingESP's, a variable-speed electric submersible pump(VSESP) was employed. By varying the frequency tothe downhole motor, it is possible to increase fluidproduction without pulling the existing downholeequipment. This paper discusses the results obtainedby using this equipment on two Lost Soldier Tensleepwells.

Resizing still will be necessary as response toinjection is seen in certain areas. However, once it hasbeen determined that a resize is justifiedeconomically, the VSESP can be used as a tool to aidwith sizing for the existing conditions. Otherapplications for this equipment also exist. A thirdwell tested is discussed briefly because it resulted in a further application.

JPT

P. 1503＾
The Interpretation of Capillary Pressure Data from Carbonate Reservoirs
Authors: Aufricht W.R. , Koepf E.H.
Published: December 2007

Introduction

The theory, measurement, and application of capillary forces in reservoir rock have been treated extensively in the various petroleum publications. These forces are of prime importance in oil production, and data on capillary properties are among the most important tools used in the study of reservoir mechanics.

The principal application of measured capillary pressure data by the production and reservoir engineer is in the determination of the initial distribution and mobility of fluids in the reservoir. The distribution refers to the magnitude of the oil and interstitial water saturations under capillary equilibrium conditions and to their variation throughout the reservoir as a result of changes in rock properties and nearness to free water. The magnitude of the water (or oil) saturation, as well as the porosity, is required in volumetric calculations of oil in place. In low permeability reservoirs, where long transition zones are common, the magnitude of the oil content, even below the depth interval where commercial rates of flow of oil can be obtained, must be evaluated since this oil contains energy available to the production of the remainder of the reservoir.

The mobility of the water phase is of particular importance in waterflood calculations since mobile water may condemn what would otherwise be a successful water flood. In reservoirs with predominantly small pores, high immobile water contents are possible. Conversely, reservoirs with predominantly large pores may contain mobile water even though the interstitial water contents are relatively low.

This presentation reviews the distribution and mobility of interstitial water contents as determined from capillary pressure data and shows typical data for various types of carbonate reservoirs. A discussion of the variations found in different types of carbonate reservoirs is given.

Discussion

Interpretation of Laboratory Data

Fig. 1 is a typical laboratory capillary pressure curve where water saturation as per cent of pore space is plotted vs capillary pressure (psig) for an air-water system. This particular curve was obtained by measurement on a sample of San Andres dolomite with inter granular-type porosity.
Phase Partitioning of Anionic and Nonionic Surfactant Mixtures
Authors: Koukounis Christos , Wade W. H. , Schechter Robert S.
Published: December 2007

The efficiency of oil recovery by waterflooding can be greatly improved by the addition of judiciously selected surfactants. Under certain conditions, when surfactant solutions are mixed with oil, microemulsions are formed that may be in equilibrium with an excess oil (Type I), an excess aqueous phase (Type II), or both (Type III). The partitioning of the surfactant between those coexisting equilibrium phases is important to consider in the design of microemulsion processes for oil recovery. This is particularly true because different phases generally move at differing velocities within the pore spaces of an oil reservoir and therefore fractionation will occur in successive stages along the flow path. This leads to chromatographic separation of the surfactant molecules. The problem is complicated because all surfactant systems are blends of molecules, and chromatographic separation will result in a change in the optimal salinity of the surfactant system. Thus, a system that is initially optimized will not remain optimized during the course of the flood.

To examine the question of selective surfactant partitioning, we varied the composition of oil/water/surfactant equilibrated systems so that they would pass through the optimal formulation region. The partitioning of anionic surfactants into the oil in Type I and Type III phase systems was small. Furthermore, binary and ternary mixtures of these surfactants were found to copartition; that is, little if any fractionation was detectable. Their collective behavior was intermediate between those of the pure components. Nonionic surfactants, unlike anionics, partition substantially into the oil phase in Type I and Type III phase systems. This was found to be an intrinsic property of the surfactant structure and not unique to those nonionic surfactant systems that are polydisperse.

Selective fractionation also was found for polydisperse nonionic surfactants.
Modeling Dependencies Between Geologic Risks in Multiple Targets
Authors: Delfiner Pierre
Published: December 2007

A single-target prospect can be characterized probabilistically by two elements: the risk or probability of success and the distribution of reserves given success. But there is no obvious way of combining the results of multiple targets into a single representative assessment.

This paper presents a simple approach for aggregating multiple targets for the purpose of prospect ranking. Reserves given success are assumed independent, and the novelty lies in the modeling of dependencies between geologic risk factors. Although interdependence can be represented by conditional probabilities, the selection of these values is a problem for most explorationists. In this paper, a more practical method is proposed. A matrix is completed for multiple targets, specifying which geologic factors are common and which are independent. An outcome tree with dependent targets is created, and the probability distribution of aggregate reserves is determined either analytically or by Monte Carlo simulation.

A case study with six targets illustrates the method. Dependencies reduce the probability of at least one success from 92% to 65% and the number of possible outcomes from 64 to 25. This allows a useful grouping by development cases. The method can be used for stacked reservoirs or portfolio analysis.
Non-Darcy Flow in Wells With Finite-Conductivity Vertical Fractures
Authors: Guppy K. H. , Cinco-Ley H. , Ramey H. J. , Samaniego-V. F.
Published: December 2007

Several methods have been proposed in the literature for analyzing drawdown data for the determination of fracture conductivity of vertically fractured wells. These techniques have proved accurate, but in some cases the fracture conductivity calculated is much smaller than anticipated. This study shows that producing fractured wells at high flow rates will cause non-Darcy effects in the fracture, resulting in a pessimistic fracture conductivity.

Numerical and semianalytical models were developed to analyze the unsteady flow behavior of finite conductivity fractures producing at high flow rates. Two methods are presented for determining the true fracture conductivity when drawdown data are available at two different flow rates. The amount of turbulent effects also is quantified by the techniques. Examples are presented to illustrate the solution methods.
Analysis of Two-Phase Tests in Large-Diameter Flow Lines in Prudhoe Bay Field
Authors: Brill James P. , Schmidt Zelimir , Coberly William A. , Herring John D. , Moore David W.
Published: December 2007

A total of 29 two-phase flow tests was conducted in two 3-mile-long flow lines in the Prudhoe Bay field of Alaska. Of these, 11 were for a 12-in.-diameter line and 18 were for a 16-in. line. Nine of the tests were in slug flow, and 20 were in froth flow. Flow rates, inlet and outlet pressures, and temperatures were measured for each test. Gamma densitometers were used to monitor flow pattern and to determine mixture densities and slug characteristics.

It was found that a modified Beggs-Brill1 pressure-loss correlation predicted culled data to within − 1.5% on the average compared with + 11.4% for a modified Dukler-Eaton2,3 correlation. Very little scatter was observed with either method.

Analysis of flow-pattern observations showed that none of the slug-flow tests were in the Schmidt4 severe slug region characterized by extremely long slugs. It also was found that the slug/froth (dispersed) flow-pattern boundary existed at a much lower liquid flow rate than predicted by either Mandhane et al.5 or Taitel and Dukler.6

Four of the slug-flow tests in 16-in. lines lasted for a sufficient time to permit statistical analysis of slug-length distributions. Sixteen additional tests on 4- and 7-in.-diameter pipe reported by Brainerd and Hedquist* were analyzed statistically. It was found that slug lengths could be represented by a log-normal distribution. A regression analysis approach was successful for estimating the mean slug length for stabilized flow as a function of superficial mixture velocity and pipe diameter. The extreme percentiles of the slug-length distribution then can be computed using standard probability tables, making possible probability statements about expected maximum slug length.

A mechanistic analysis of the slug-flow tests resulted in equations for predicting slug velocities, liquid holdup in both the liquid slug and the gas bubble, and the volumes of liquid that are produced and overrun. These parameters are important for predicting liquid-slug effects on separator performance.
Characterization and Oil Recovery Observations on a Series of Synthetic Petroleum Sulfonates
Authors: Malmberg Earl W. , Gajderowicz Carolyn C. , Martin F. David , Ward Jill S. , Taber J. J.
Published: December 2007

Synthetic sulfonates for application in enhanced oil recovery are of increasing interest. Because of the need to explore the range of candidates potentially available at various costs from the petrochemical industry, a series of nine samples was prepared for distribution with financial support of the U.S. DOE. This paper briefly describes the samples and, in more detail, the characterization of the samples for oil recovery. The characterization included determination of optimal salinity, stability of aqueous dispersions in brines containing sodium chloride and calcium ion, and oil recovery and loss of sulfonate in 1-ft (0.305-m) Berea cores.
Inferring Interwell Connectivity Only From Well-Rate Fluctuations in Waterfloods
Authors: Albertoni Alejandro , Lake Larry W.
Published: December 2007

This paper presents a practical technique to quantify communication between wells in a reservoir using only production and injection rate data. The technique combines a constrained multivariate linear regression analysis with diffusivity filters to provide information about permeability trends and the presence of transmissibility barriers. The method was developed and tested using a numerical simulator and then applied to a waterflooded field in Argentina. The simulation results indicate that the connectivity between wells is described by coefficients that only depend on geology and relative position between wells; they are independent of injection/production rates. The results of this work can be used to improve the performance of an existing waterflood by suggesting how well patterns might be changed or managed. They could also be used to model flow in the reservoir.
Innovative Critical Sour Gas Extended Production Test Through Surface Coiled Tubing
Authors: Campbell S. F. , Pettigrew S. M.
Published: December 2007

This paper describes the deliverability test of a critical, sour, natural-gas well that uses coiled tubing as a surface pipeline. Conventional production deliverability tests are constrained by regulatory limitations on emissions and flaring, affecting test duration and reservoir evaluation. Conventional tests also carry significant environmental impact, and the lost revenue from flared gas hampers the economic justification of the test. This paper describes the concept, the background analysis, and the field production test. A safety-focused procedure was developed using surface coiled tubing for in-line testing of high-rate, critical, sour gas wells. This prototype method allows a proper evaluation of a well without the commitment and installation of a permanent pipeline, the volume restraint imposed by regulatory limitations, harm to the environment, and compromising economic value. This method of well production deliverability tests is projected to become an attractive alternative for the Alberta oil and gas industry.
New Developments in Aerated Mud Hydraulics for Drilling in Inclined Wells
Authors: Sunthankar A. A. , Kuru E. , Miska S. , Kamp A.
Published: December 2007

An experimental study of aerated mud flow in an inclined well has been conducted, and the results are presented in this paper.

Extensive experiments were performed in a unique field-scale low-pressure flow loop (8×4.5 in. annular geometry and 90 ft long) in an inclined position (15° from vertical) with and without drillpipe rotation. Water and an aqueous polymer solution [CMC (sodium carboxymethyl cellulose)+XCD (xanthan gum)+water] were used as the liquid phase. The liquid flow rate was in the range of 100 to 325 gal/min. The air flow rate was in the range of 8 to 85 scf/min. Measurements of pressure drop and average liquid holdup were carried out for the entire annular section. To our knowledge, no such data has been published previously.

The two-phase flow patterns were identified by visual observations. Bubbly and slug/churn (intermittent) flow were observed for the ranges in the chosen test matrix.

The flow-pattern boundaries proved to be shifted as compared to pipe flow. The transition between bubbly and slug flow was observed at a void fraction of 0.32 as compared to that reported for pipe flow (0.25) for air-water flow. On the contrary, for air-aqueous polymer fluid, flow was the same as for air-water pipe flow (0.25). For flow with drillpipe rotation, churn flow was observed instead of slug flow because of the churning of slugs by the rotating drillpipe.

There was no significant effect of drillpipe rotation on the pressure drop for air-water flow. However, in the case of air-aqueous polymer fluid flow, the pressure drop decreased with drillpipe rotation.

A higher pressure drop was observed in case of air-aqueous polymer fluid flow as compared to air-water flow.
Slimline Dual Detector Density Logging - A Semitheoretical but Practical Approach to Correction and Compensation
Authors: Samworth J. Roger
Published: December 2007

A semiempirical approach to particular problems encountered in quantitative density logging with slimline logging tools is made. Equations based on known "physics" are employed to avoid problems encountered if empirical relationships alone are used. The simplest assumptions consistent with satisfactory results are outlined, and sample logs illustrate the effects of dual detector compensation.

Introduction

The log described in this paper is part of a multifunction sonde (gamma ray and caliper also are included as well as two density logs) developed to fulfill a requirement for a slimline one-run tool for one-man coal logging operations. The log response and compensation theory used also has shown itself to be readily extendable to logging in the higher 2- to 3-g/cm3 density region. The original purpose of the dual detector density log was to provide a thin-bed resolution capability with a good quantitative density measurement from the long-spacing detector. The spacings were chosen with these requirements in mind and were developed in an earlier generation of single-function tools. A semiempirical approach was taken to the density response equation with satisfactory results, and more recently, efforts to utilize the two logs to give densities compensated for tool standoff and (to some extent) for caving have shown some success.

Slimline Sonde Design Constraints

The one-man operation and slimline requirements indicated a sonde diameter of less than 5 cm and of manageable length (eventually around 3.5 m). The small diameter and desire for relative simplicity made necessary two other basic constraints.1. A limited volume was available for collimation of the source (Cesium 137) and the detector. This meant that a much larger borehole effect was present than is usual with larger-diameter tools and necessitated use of the semiempirical theory described later.2. An articulating detector shoe for the density logs was not used, since the sonde was eccentered as a whole by a single eccentering arm (Fig. 1).To reduce radiation counting statistics, high-efficiency scintillation counters were used for both detectors. Downhole count-rate dividers also were used to eliminate dead-time losses that can be caused by low-bandwidth logging cables. These dividers are such that the resolution and low counting statistics provided by the scintillation counters are in no way provided by the scintillation counters are in no way compromised. The detector dead time still remains, however, and is dealt with later.

Response Equation

For the preceding reasons, a semiempirical approach was thought to be necessary to allow a reasonably comprehensive relationship between the detector count rate and formation density to be established. The procedure should, however, apply equally to other similar tools. Let us begin with a relationship between count rate and density in an isotropic medium:

I = P e (-mp),......................(1)

JPT

P. 1316
Laboratory-Based Evaluation of Gas Well Deliverability Loss Caused by Water Blocking
Authors: Kamath Jairam , Laroche Catherine
Published: December 2007

Water blocking caused by invasion of completion fluids has been suspected to reduce gas well deliverability.1–5 However, this effect has not been quantified. We report results of a laboratory program to measure the water-blocking effect in core samples from a gas field. These data were mapped to a wellbore model to make deliverability predictions.

The laboratory data consist of gas flow rate as a function of injected gas pore volume for various liquids (brine, methanol, toluene, isopropyl alcohol, and brine-methanol mixtures) at two saturation states (fully saturated with liquid, and containing liquid and trapped gas). We injected over 10,000 PV of gas in each test to mimic near-wellbore conditions. The data showed that the liquid displacement regime was followed by a mass transfer regime.

The wellbore model had a time varying skin to account for the cleanup of the fluid invaded ("water-blocked") region. Cleanup occurs as gas flows past this high liquid-saturated region and removes liquid by displacement and mass transfer. We used the laboratory data to relate the reduced permeability of this region to pore volumes of gas throughput.

We find that any loss in gas well deliverability recovers in two phases. The first phase corresponds to fluid displacement ("flowback period") and lasts for a few days at most. The second phase is slower and can last several months. Here, evaporation causes the deliverability to slowly increase. It is in this regime that adding volatile fluids, such as methanol, to the completion brines has advantages.
Estimating Geomechanical Properties Using an Integrated Flow Model
Authors: Fanchi J. R.
Published: December 2007

We show how to obtain inexpensive estimates of geomechanical parameters by explicitly coupling a petrophysical model with a traditional flow simulator. The usefulness of development geophysical information from the resulting integrated flow model is illustrated for improved recovery and coalbed methane production processes.
Transient Rate Decline Analysis for Wells Produced at Constant Pressure
Authors: Ehlig-Economides C. A. , Ramey H. J.
Published: December 2007

Although constant-rate production is assumed in the development of conventional well test analysis methods, constant-pressure production conditions are not uncommon. Conditions under which constant-pressure flow is maintained at a well include production into a constant-pressure separator or pipeline, steam production into a backpressured turbine, or open flow to the atmosphere.

To perform conventional well test analysis on such wells, one common procedure is to flow the well at a constant rate for several days before performing the test. This procedure is not always effective, and often the delay could be avoided by performing transient rate tests instead. Practical methods for transient rate analysis of wells produced at constant pressure are presented in this paper. The most important test is the analysis of the rate response to a step change in producing pressure. This test allows type-curve analysis of the transient rate response without the complication of wellbore storage effects. Reservoir permeability, porosity, and the wellbore skin factor can be determined from the type-curve match. The reservoir limit test is also important. Exponential rate decline can be analyzed to determine the drainage area of a well and the shape factor.

The effect of the pressure drop in the wellbore due to flowing friction is investigated. Constant wellhead-pressure flow causes a variable pressure at the sandface because the pressure drop from flowing friction is dependent on the transient rate. Finally, for testing of new wells, the effect of a limited initial flow rate due to critical flow phenomena is examined.
Gas Cycling and the Development of Miscibility in Condensate Reservoirs
Authors: Jessen K. , Orr F. M.
Published: December 2007

This paper presents a detailed analysis of the development of miscibility during gas cycling in condensate displacements and the formation of condensate banks at the leading edge of the displacement front.

Dispersion-free, analytical 1D calculations are presented for enhanced condensate recovery by gas injection. The analytical approach allows investigation of the possible formation of condensate banks (often at saturations that exceed the residual liquid saturation) and allows fast screening of optimal injection-gas compositions. We describe construction of the analytical solutions, a process that differs in some ways from related displacements for oil systems. All analytical solutions are verified by numerical calculations.

We use an analysis of key equilibrium tie lines that are part of the displacement composition path to demonstrate that the mechanism controlling the development of miscibility in gas condensates may vary from first-contact miscible drives to pure vaporizing and combined vaporizing/condensing drives. Depending on the compositions of the condensate and the injected gas, multicontact miscibility can develop at or below the dewpoint pressure of the reservoir-fluid mixture.

Finally, we discuss the possible impact on performance prediction of the formation of a mobile condensate bank at the displacement front in near-miscible gas-cycling/injection schemes.
Design and Productivity of Gravel-Packed Completions
Authors: Penberthy W.L. , Cope B.J.
Published: December 2007

Field-scale gravel-pack studies have shown that openhole gravel packs have higher productivity than cased-hole gravel packs; however, in the latter, well productivity can be improved by increasing the size and number of perforations. Results also show that cased-hole gravel-pack productivity can be enhanced by prepacking gravel outside the perforations.

Introduction

Gravel packing to exclude formation sand from produced fluids has been used as a completion technique for oil and gas wells for the past 40 to 50 years. However, the technology used in early gravelpack work was borrowed from the water-well industry, which for many years had been applying several types of mechanical sand retention devices to prevent sand production from produced groundwater.Early oil and gas completions, similar to those used in water wells, were what normally is referred to as openhole gravel packs (Fig. 1). Accurately sized gravel was placed around a slotted liner to act as a filter for formation sand. Subsequent completions sometimes consisted of cementing casing through the formation and perforating to communicate with the oil reservoir. This technique became common with the advent of gun and jet perforating, because the exclusion of water or gas was sometimes difficult to achieve in openhole gravel packs.If fluid production also resulted in sand production, cased-hole gravel packs were performed inside the well's casing (Fig. 1). The well productivity of these packs, however, quickly was recognized as being far below that experienced with the openhole packs. Field experience showed that, in general, the productivity of prepacked cased-hole completions was sometimes only 25 to 33% of that of the openhole pack, whereas the lack of prepacking could cause productivity losses of greater than 95%, as shown in Table 1.As a result of these problems, a whole new dimension in gravel packing arose with the cased-hole gravel-pack completion, since substantially different techniques and procedures are required to perform these completions properly in comparison with openhole gravel packs.The productivity limitations encountered in cased-hole gravel packs prompted numerous engineers and researchers to begin work to define and solve problems related to them. Early work on the proper gravel size required for effective sand control indicated that gravel/sand ratios of from 5:1 to 13:1 should be used. Formation sand design points anywhere from a cumulative of 10 to 70% based on a representative formation sand sample were recommended.Most of the early research was conducted in linear-flow packs operated under single-phase flow conditions. Additional work indicated that the main restriction to flow was sand-filled perforations and that for maximum productivity, plugging in the perforation with formation sand must be avoided. The remedy for this situation has been to pressure-pack the gravel through the perforation so that the gravel in the perforation is of the highest permeability capable of preventing the production of formation sand.

JPT

P. 1679＾
Entrainment and Deposition of Fine Particles in Porous Media
Authors: Gruesbeck C. , Collins R. E.
Published: December 2007

Entrainment and redeposition of naturally occurring fine particles in porous media has been suggested as a mechanism leading to abnormal decline in productivity of producing wells. This paper describes the results of studies conducted to determine factors affecting this phenomenon. Experimental work done as part of this study provides the basis for a proposed phenomenological theory of entrainment and deposition. The central concept of this theory is representation of both particle and pore size distributions by partitioning the porous medium at any cross section into parallel plugging and nonplugging pathways. This simple model appears to be completely adequate for describing a broad class of filtration and entrainment phenomena. We have shown that fines entrainment and redeposition are mechanisms that can cause abnormal productivity decline and are phenomena restricted to the near-wellbore region.
A Recipe for Residual Oil Saturation Determination
Authors: Kidwell Charles M. , Guillory Abner J.
Published: December 2007

Before initiation of a CO2 tertiary recovery project, a residual oil saturation study was conducted in the deep, hot, pilot reservoir. The paper discusses the many technical problems that had to be resolved before and during the study. The problems confronted are outlined so that the procedure can be used much like a cookbook in designing future studies in similar reservoirs.

Introduction

With the advent of increased oil prices, tertiary recovery techniques are becoming more economically attractive. The necessity for residual oil saturation measurements will become more common since these numbers are mandatory in defining the profitability of any tertiary project. Routine procedures to measure this saturation in situ become necessary. However, we are dealing with such a delicate system that the details of planning such an operation become very involved.In 1978 Shell Oil Co., in conjunction with the U.S. DOE, conducted a residual oil saturation study in a deep, hot, high-pressured U.S. gulf coast reservoir. The work was conducted before initiation of a CO2 tertiary recovery pilot.Primary discussion in this paper centers around planning and results of a "log-inject-log" (LIL) operation used as a prime method to determine the residual oil saturation. Several independent methods were used to calculate the residual oil saturation in the subject well in an interval between 12,910 and 12,920 ft (3935 and 3938 m). In general, these numbers were in good agreement and indicated a residual oil saturation between 22 and 24%.A free-gas saturation was measured in the residual oil saturated interval. This saturation may well be typical of U.S. gulf coast reservoirs that are below the original bubble point at the time tertiary recovery is initiated. As a result, residual oil saturation typically may be less than those values determined by "flood pot" or countercurrent imbibition tests run in the laboratory. Likewise, residual saturations conventionally measured by openhole resistivity and porosity logs may be residual hydrocarbon and not residual oil saturations.The test was conducted in the "S" Sand Reservoir B (SRB), a 12,800-ft (3901-m) deep U.S. gulf coast reservoir in Weeks Island field, Iberia Parish, LA. The project setting is depicted in Fig. 1. The SRB initially contained two oil columns with more than 3 million bbl (476,700 m3) of in-place oil. Virtually all of this was in the pilot area. Before initiation of the tertiary project, the SRB had been flooded with fresh water. The remaining oil column had been produced to an estimated thickness of 23 ft (7 m). The 900 acre-ft (1 110 140 m3) of the SRB we propose to displace should contain a minimum of 258,000 bbl (40 996 m3) of water-drive residual oil. If the process is proved successful in the SRB, other major watered-out reservoirs in Weeks Island field have an estimated tertiary potential of 26 million bbl (4 131 400 m3) of oil which could be recovered by CO2 displacement.

JPT

P. 1999＾
Water Flooding a High Water-Cut Strawn Sand Reservoir
Authors: Roebuck I.F. , Crain Leon L.
Published: December 2007

The Baylor County Water flood Unit No. 1 is located in the East Seymour Strawn field, approximately 11 miles east of the city of Seymour, Tex. Production is from a stratigraphic-trap Strawn sand reservoir at an average depth of approximately 4,675 ft, with the reservoir almost completely underlain by water. After seven years of primary production with a partial water-drive mechanism, and with producing water-cut at an average of 75 per cent, the field was unitized and a downdip peripheral water-injection project was installed. This paper discusses the geology, rock and fluid properties, and field producing characteristics. The producing history, before and after the beginning of injection, is presented as are the detailed projections of both primary and water-injection performances and the various factors considered in the design of this successful water-injection program.

Introduction

The Baylor County Waterflood Unit No. 1, operated by Sheets and Walton Drilling CO. of Breckenridge, Tex., is located in the East Seymour Strawn field, Baylor County, Tex. (Fig. 1). This field is approximately 11 miles east of the city of Seymour in Sections 196, 197, 206 and 207 of the T. and N. O. R. R. Survey. The producing reservoir is a stratigraphic-trap Strawn sandstone of Pennsylvanian age with an active, but limited, aquifer. By July, 1960, when water-injection operations were initiated, oil producing rates had declined to less than 8 B/D/well, and the producing water-cut had increased to an average of 75 per cent. In spite of the adverse geological conditions present with respect to water content and position in the reservoir, unitized water- injection operations have been both economically and technically successful. This paper presents the geological and engineering data and interpretations which led to the application of water- injection operations, and describes the production performance under injection operations.

History and Development

Production in the vicinity of the Baylor County Waterflood Unit No. 1 was discovered in June, 1950, with the completion of the J.J. Lynn, First National Bank of Fort Worth No. 1 well as a Caddo lime producer (Fig. 2). In Sept., 1951, the J.J. Lynn, First National Bank of Bowie No. 1 well was completed as a Strawn sand producer in what was designated as the Seymour Strawn field with a total of 11 producing oil wells. The East Seymour Strawn field was discovered in Sept., 1952, with the completion of the J.J. Lynn, Claude Cowan "H" No. 1 well. By Dec., 1955, a total of 24 Strawn sand oil wells had been completed, 23 of which were in what is now designated as the Baylor County Waterflood Unit No. 1 (i.e., the Cowan "B", "J" and "H" leases, Sections 206 and 207, T. and N. O. R. R. Co. Survey, Baylor County, Tex.).

JPT

P. 845ˆ
ASP System Design for an Offshore Application in La Salina Field, Lake Maracaibo
Authors: Hernández Clara , Chacón Larry J. , Anselmi Lorenzo , Baldonedo Abel , Qi Jie , Dowling Phillip C. , Pitts Malcolm J.
Published: December 2007

La Salina Field, on the eastern coast of Lake Maracaibo, Venezuela, was designated as a Laboratorio Integrado de Campo (Integrated Field Laboratory, or IFL) by PDVSA to evaluate the potential application of different EOR processes. One of the main goals at La Salina IFL was to evaluate the alkaline-surfactant-polymer (ASP) technology potential in an oil reservoir near the end of its waterflood life.

La Salina produces a medium-gravity crude oil (25°API) from the LL-03/Phase III Miocene reservoir at 915 m (3,000 ft). The feasibility of applying the ASP technology was based on a series of experiments including fluid compatibility, chemical thermal stability, phase behavior, interfacial tension between crude oil and ASP solution, chemical retention by the porous media, and physical simulation with reservoir core samples. The laboratory design involved 23 commercial surfactants, five polymers, and two alkalis. Interfacial tension reductions in excess of 25,000-fold were observed for a variety of ASP solutions. Type II- and Type III phase behaviors were observed. Linear coreflood results indicate that high-molecular-weight, partially hydrolyzed polyacrylamide polymers can be injected into La Salina sand. Radial sandpack floods produced an average oil recovery of 45.6% original oil in place (OOIP) with water injection. Injection of 30% pore volume of ASP solution, followed by 30% pore volume of polymer drive solution, produced (on average) an additional 24.6% OOIP for an average total oil recovery of 70.2% OOIP.

The design of the injection plant for La Salina is a challenging task because this will be the first offshore application of the ASP technology in the world. The initial decision for the plant design was to use an existing platform instead of a barge for the construction of facilities. As a result, critical parameters such as treatment sequence, equipment footprint, and storage space for injected and treatment chemicals were considered. Preparation and transport of a phase-stable ASP solution through the injection lines and into the reservoir are crucial. Designed chemical concentrations and physical characteristics must be maintained.
Theoretical and Experimental Investigation of Isothermal Compositional Grading
Authors: Ratulowski J. , Fuex A. N. , Westrich J. T. , Sieler J. J.
Published: December 2007

A centrifuge system capable of producing a potential difference across a live oil column equivalent to 1,000 ft of gravitational head was designed and tested. Initial tests on a simple ternary system yielded results similar to equation-of-state (EOS) models. A black-oil sample from a Gulf of Mexico field, Bullwinkle J2-RB sand, exhibiting compositional gradients was segregated in the centrifuge. Experimental results from the centrifuge were similar to field values, indicating that the large variation in composition observed for this field may be attributed to gravitational segregation alone.

From the results of these two sets of experiments and the subsequent analysis of the graded fractions, we can conclude that significant compositional variation of reservoir fluids not near their vapor/liquid critical points can be caused by gravity alone. The grading phenomenon is sensitive to the saturate/aromatic balance of the oil. Existing EOS models did not correctly predict the compositional variations in fluids like the Bullwinkle J2-RB because pseudocomponents generated from volatility distributions have a fixed saturate/aromatic character. It is subtle changes in the saturate/aromatic balance that drive the grading phenomena for these fluids.
Improved Permeability Estimates in Carbonate Reservoirs Using Electrofacies Characterization: A Case Study of the North Robertson Unit, West Texas
Authors: Mathisen Trond , Lee Sang Heon , Datta-Gupta Akhil
Published: December 2007

We propose a simple, cost-effective approach to obtaining permeability estimates in heterogeneous carbonate reservoirs using commonly available well logs. Our approach follows a two-step procedure. First, we classify the well-log data into electrofacies types. This classification does not require any artificial subdivision of the data population but follows naturally based on the unique characteristics of well-log measurements, reflecting minerals and lithofacies within the logged interval. A combination of principal component analysis (PCA), model-based cluster analysis (MCA), and discriminant analysis is used to identify and characterize electrofacies types. Second, we apply nonparametric regression techniques to predict permeability using well logs within each electrofacies.

Our proposed method has been successfully applied to the North Robertson Unit (NRU) in Gaines county, west Texas. Previous attempts to derive permeability correlations at the NRU have included rock-type identification using thin-section and pore-geometry analysis that can sometimes be expensive and timeconsuming. The proposed approach resulted in improved permeability estimates, leading to an enhanced reservoir characterization, and can potentially benefit both daily operations and reservoir simulation efforts. The successful field application demonstrates that the electrofacies classification used in conjunction with sound geologic interpretation can significantly improve reservoir descriptions in complex carbonate reservoirs.
Asphaltene Precipitation and Alteration of Wetting: The Potential for Wettability Changes During Oil Production
Authors: Al-Maamari Rashid S. H. , Buckley Jill S.
Published: December 2007

Wettability controls the distribution and flow of immiscible fluids in an oil reservoir and thus plays a key role in any oil-recovery process. Once thought to be a fixed property of each individual reservoir, it is now recognized that wettability can vary on both microscopic and macroscopic scales. Polar oil components can adsorb onto the pore-bounding mineral surfaces by several different mechanisms. In this study, we explore a transition in the mechanism of wettability alteration that relates to the asphaltene fraction and its stability in the oil phase.

Asphaltene stability was varied by adding n-heptane to samples of five crude oils. Conditions tested ranged from those in which asphaltenes were stable to mixtures in which aggregates formed and separated from the oil. The onset condition—in which the first asphaltene particles become visible—provides a reference point with respect to asphaltene stability in each crude-oil sample.

Muscovite mica sheets, treated with brine and with the crude oil/heptane mixtures, were examined using contact angles between decane and water as a measure of altered wettability on the oil-treated surfaces. A significant increase in oil-wet conditions very near the onset of asphaltene precipitation was observed with four of the five oils, indicating the potential for wetting changes during the course of oil production if conditions of asphaltene instability are approached. Implications of changes in the mechanism of wetting alteration during the course of production from an oil reservoir are considered.
Propagation of Chromium(III) Acetate Solutions Through Dolomite Rock
Authors: Jin H. , McCool C. S. , Willhite G. P. , Green D. W. , Michnick M. J.
Published: December 2007

Chromium(III)-polymer gel systems are often used in permeability modification treatments for flow control. In-depth treatment of the carbonate rock matrix by these systems is of concern because rock-fluid interactions can lead to loss of chromium and may limit the penetration of a gel treatment. This paper describes a study of chromium retention in dolomite cores in the absence of polymer and demonstrates that precipitation of chromium is the principal retention mechanism. Displacement experiments were conducted in which chromium(III) acetate solutions were continuously displaced at different flow rates through Baker dolomite cores with permeabilities from 19 to 25 md. In some experiments, the cores were shut in and the resident fluid displaced and analyzed to determine chromium retention during the shut-in period.

There was significant retention of chromium in the core in both continuous and shut-in experiments. In the continuous displacements, effluent concentration profiles were a function of flow rate, indicating that the retention was a rate-dependent process. In the range of concentrations studied, 0 to 1% by weight, the presence of KCl increased the retention rate. At the lowest flow rate used, effluent chromium concentration approached a steady-state value that was much smaller than the injected concentration. The retention capacity of the rock appeared to be infinite.

Chromium concentrations at various residence times were compared to values predicted from a kinetic model developed for precipitation from bulk solutions. The kinetic model fit the precipitation rate data well and is consistent with the conclusion that precipitation is the principal retention mechanism. However, the induction period observed in bulk solutions was not present in the data taken in the cores. Precipitation occurred faster in the cores than in the batch experiments. The experimental results indicate that chromium is precipitated at a relatively high rate when chromium acetate solution is in contact with dolomite core material. This loss of chromium may inhibit gelation and limit the depth of penetration of a gel system in dolomite matrix rock.