bluuebunny/crossref_metadata_2025 huggingface dataset:
Phase Behavior of CO2 and Crude Oil in Low-Temperature Reservoirs
Authors: Orr F. M. , Yu A. D. , Lien C. L.
Published: December 2007

Phase behavior of CO2/crude-oil mixtures which exhibit liquid/liquid (L/L) and liquid/liquid/vapor (L/L/V) equilibria is examined. Results of single-contact phase behavior experiments for CO2/separator-oil mixtures are reported. Experimental results are interpreted using pseudoternary phase diagrams based on a review of phase behavior data for binary and ternary mixtures of CO2 with alkanes. Implications for the displacement process of L/L/V phase behavior are examined using a one-dimensional finite difference simulator. Results of the analysis suggest that L/L and L/L/V equilibria will occur for CO2/crude-oil mixtures at temperatures below about 120° F (49 °C) and that development of miscibility occurs by extraction of hydrocarbons from the oil into a CO2-rich liquid phase in such systems.
Generation of Low-Order Reservoir Models Using System-Theoretical Concepts
Authors: Heijn T. , Markovinovic R. , Jansen J.-D.
Published: December 2007

We present five methods to derive low-order numerical models of two-phase (oil/water) reservoir flow, and illustrate their features with numerical examples. Starting from a known high-order model, these methods apply system-theoretical concepts to reduce the model size. Using a simple but heterogeneous reservoir model, we illustrate that the essential information of the model can be captured by a limited number of state variables (pressures and saturations). Ultimately, we aim at developing computationally efficient algorithms for history matching, optimization, and the design of control strategies for smart wells. In this study we applied (1) modal decomposition, (2) balanced realization, (3) a combination of these two methods, (4) subspace identification, and (5) proper orthogonal decomposition (POD), also known as principal component analysis, Karhunen-Loève decomposition, or the method of empirical orthogonal functions. Methods 1 through 4 result in linear low-order models, which are only valid during a limited time span. However, the POD results in a nonlinear model that remains valid over a much longer period. Methods that result in linear low-order models are not very promising for speeding up reservoir simulation. POD, however, has the potential to improve computational efficiency in the case of multiple simulations of the same reservoir for different well operating strategies, but further research is required to quantify this scope. The potential benefit of low-order models is therefore mainly in the development of low-order control algorithms, and in history matching, where the use of reduced models may form an alternative to classical regularization methods.
Interplay of Phase Behavior and Numerical Dispersion in Finite-Difference Compositional Simulation
Authors: Jessen Kristian , Stenby Erling H. , Orr Franklin M.
Published: December 2007

Compositional simulation of multicontact miscible (or nearmiscible) gas injection problems is typically performed by use of numerical finite-difference (FD) schemes. Such simulations are intrinsically affected by numerical dispersion.* In this paper, we propose a method to assess the sensitivity of a particular displacement calculation to the effects of numerical dispersion for systems with realistic multicomponent fluid descriptions. We use two simple ternary systems to illustrate how dispersion and convection interact to determine displacement composition paths and to define a "dispersive distance." We show how the dispersive distance relates to displacement performance with a detailed analysis of grid size effects on the recovery predictions for 1D displacements of a CH4-C4-C10 system by pure N2 and mixtures of N2 and CH4. We then show that the sensitivity of multicomponent compositional simulations also correlates well with the dispersive distance. We demonstrate that quantitative difference between oil recovery predicted by coarse-grid numerical simulations, and values obtained from analytical solutions to the conservation equations, can be estimated well from calculating the distance between the dilution line and the composition path predicted by the method of characteristics. Finally, we apply the assessment of sensitivity to 2D displacements in a heterogeneous porous medium to demonstrate the interplay of phase behavior, adverse mobility, heterogeneity, and numerical dispersion.
Experiments and Analysis of Heavy-Oil Solution-Gas Drive
Authors: Sahni A. , Gadelle F. , Kumar M. , Tomutsa L. , Kovscek A. R.
Published: December 2007

We provide a general framework for interpreting heavy-oil solution-gas-drive experiments. Evolution of the gas phase below the thermodynamic bubblepoint is investigated with dimensionless scaling groups, mechanistic modeling, and experiments. Carefully planned and monitored depletion experiments are conducted to evaluate pre- and post-critical gas-saturation behavior. In-situ phase saturations are measured with X-ray computerized tomography (CT) scanning. These data are used in conjunction with differential-pressure measurements along the core to obtain phase mobilities. It is demonstrated that most laboratory heavy-oil-depletion experiments show nonequilibrium effects that depend on the oil-phase viscosity and depletion rate. Factors leading to the coalescence of gas-bubble clusters and development of bulk gas flow are illustrated with examples, along with an empirical correlation for critical gas saturation (Sgc). Examination of field-pressure gradients and flow rates suggests that dispersed gas flow may occur close to the wellbore or near wormholes, if present.
Identification of Mixtures of Waters from Chemical Water Analyses
Authors: McKinnell J.C.
Published: December 2007

Identification of complex mixtures of waters presents many problems that can be solved by graphical methods described in this paper. Examples are presented to show the application of these methods to the correlation of oilfield waters and the determination of the percentage of each water in mixtures of two and three waters.

Introduction

Correlation of waters and identification of mixtures of two and three waters is important in secondary recovery evaluation studies and studies involving underground movement of waters. The importance of such studies suggests the need for a method to correlate a great number of water analyses to accurately identify and improve the understanding of mixtures of waters.

Geochemical analyses of waters furnish a quantitative measure of each of the ions present in a water. Table 1 shows a portion of the data on many oilfield water analysis report forms in use today. Under "parts per million" are listed the quantitative amounts of each ion in milligrams per liter. Following the work of Stabler and Palmer, some laboratories have reported additional data to indicate the reaction capacity, or reacting value of each ion. Table 1 lists data under two subheads for the "reacting value". Under the first subhead, the reacting value is reported in gram equivalents per million, hereinafter called equivalents per million. This value is determined by multiplying milligrams per liter of the ion by a factor equal to the reciprocal of the equivalent weight of the ion. Under the second subhead (per cent) is listed the percentage of each ion based on the total equivalents per million.

Sodium is not usually an analyzed value in routine analyses, but is determined by the difference between total negative equivalent per million values and the sum of all of positive ion values for which analyses were made. This difference is reported as sodium, hereafter labelled "sodium". On this basis, the, subtotals of the equivalent per million and per cent reacting values of the positive and negative ions are equal.
Using Model Basin Tests to Predict Motion Characteristics of Floating Rigs
Authors: Beck R.W.
Published: December 2007

A scale model of a floating rig was subjected to motion tests in a wave basin under a variety of wave conditions representing actual wave heights and periods experienced in Lake Maracaibo in Venezuela. The motion of the rotary table relative to a fixed wellhead was recorded on motion picture film. The observed vertical, lateral and fore and aft motion was then related graphically to wave height and period. These data permitted predictions to be made that the actual floating rig would be able to work effectively more than 98 per cent of the time, and that the maximum motion to be expected under severe storm conditions would not endanger the floating rig, or the wellhead and foundation. The actual floating rig went into operation in mid-1963. It is equipped with a three-dimensional continuous motion recorder. During a prolonged test period, the floating rig operated effectively 99.44 per cent of the time, and the maximum motion experienced to date is 83 per cent of the theoretical maximum predicted from the model basin test data.

Introduction

Lake Maracaibo in Western Venezuela is a brackish body of water 110 miles long by 70 miles wide and a little over 100 ft deep. The Bolivar coastal field, one of the largest oilfields in the world, is in the northern half of the lake. Creole Petroleum Corp. is one of the major operators in Lake Maracaibo. A Creole drilling rig operating in the lake is shown in Fig. 1. The derrick and drawworks are mounted on a reinforced concrete pile foundation which has a working load capacity of 400 tons. The rest of the drilling equipment is carried on a standard drilling tender which is 180 ft long by 70 ft wide and has a normal operating displacement of about 2,700 tons. The heavy-duty foundation used on Creole's Lake Maracaibo wells represents about 30 per cent of the total well investment. If the foundations had to support only the wellhead and working platform and not the heavy drilling loads, a simplified tripod design could be used and the cost would be substantially reduced. With this in mind, Creole decided to examine the possibilities for converting a standard drilling tender to a floating rig by supporting the rig outboard of the front end of the barge. This system would permit the use of a tripod wellhead support platform costing only about one-half as much as a conventional foundation. Although it appeared probable that a floating rig of the type contemplated could be used successfully, it was deemed advisable to perform sufficient model basin tests to obtain quantitative answers regarding barge motion under the conditions to be expected in the lake.

Test Methods

The Model

Creole already had on hand an accurate 1:48 scale model of a standard drilling tender and drilling rig. A rig-support structure was prepared for the model so the rig could be mounted either over the bow or over the side. Photographs of the model rig are shown in Fig. 2.

JPT

P. 1361ˆ
Development of the Critical Gas Saturation
Authors: de Swaan A.
Published: December 2007

Introduction

The critical or threshold gas saturation is a specific property of the porous medium and internal fluids. property of the porous medium and internal fluids. Compared with the experimental research on the subject, I the theory of gas saturation development to its critical value and the significance of this growth on reservoir performance have received little attention. For a volumetric reservoir - i.e., one with negligible water influx and negligible change of rock porosity with internal fluid pressure change, and with porosity with internal fluid pressure change, and with water production and expansion also considered zero - the usual procedure to compute gas saturation development is the material balance equation:

Bo - Boi + Bg (Rsi- Rs) Np=------------------------ N,..............(1) Bo + Bg (Rp - Rs)

with average reservoir pressure below the bubble-point pressure and Sg less than Sgc. In Eq. 1,

1 Np Rp = --- RsdNp.........................(2) Np 0

In words, only the solution gas has been produced, since the gas saturation remains insufficient for gas flow. The recovery percentage is obtained from the material balance equation; the gas saturation is obtained from the recovery percentage. Eq. 1 is an involved integral equation of a type unknown to me. Np is a self-dependent variable with the limit of the integral in the denominator - Eq. 2. In Ref. 2, Eq. 1 is not presented in the form shown but as a numerical solution procedure that simplifies the presentation. In fact, this numerical solution is an everyday affair for the practicing engineer. An alternative formula is presented. presented. JPT

P. 907
Oil-Recovery Surfactant Formulation Development Using Surface Design Experiments
Authors: Gerbacia W. , McMillen T. J.
Published: December 2007

Experiments were conducted to study the effects of three surfactant flooding variables on oil recovery and interfacial tension (IFT). The variables studied were the fraction of high-equivalent-weight sulfonate, the cosurfactant hydrophile-lipophile balance (HLB), and the weight ratio of cosurfactant to sulfonate. We then evaluated the data statistically, obtaining optimal formulations for this data space. From trends observed in the investigation, a high crude-oil recovery formulation was developed for this crude-oil/brine system. All three variables had a significant effect on oil displacement. The high-equivalent-weight sulfonate was detrimental to recovery of the crude oil used in this investigation. Systems with low measured interfacial tensions did not produce the highest recoveries. This is explained by extraneous dominating effects.
A Copper Ion Displacement Test for Screening Corrosion Inhibitors
Authors: Hughes William B.
Published: December 2007

A method for the selection of the most suitable corrosion inhibitor for a particular system is given. The method involves the evaluation of surface passivity by means of copper ion displacement after the metal surface has been subjected to the corrosive atmosphere. The application of the method to the selection of suitable inhibitors for use in producing wells is described.

Correlation with recognized laboratory tests has been found to be good within the limitations of the test. The use of the test to evaluate inhibitor persistence is described.

Introduction

Corrosion as it is associated with the industry shows wide variations in its qualitative as well as its quantitative aspects. This complicates the work of the corrosion engineer.

In the past few years the efforts of the corrosion engineer have been further taxed by the large numbers of products being marketed as corrosion inhibitors by various manufacturers. These products are submitted to him together with a limited amount of data to support their use as inhibitors. The data are usually authentic and reliable yet all too often when these products are applied to an actual corrosive system the results are disappointing due to the ineffectiveness of the inhibitor and the corrosive system.

The corrosion engineer must select a comparatively limited number of inhibitors for field trial from the large number available. The selection is usually made on the basis of a standardized laboratory test such as that adopted by the National Association of Corrosion Engineers or by field experience in an area; however, testing of this type is discouraging on large numbers of compounds, particularly in view of the specificity of environment.

It has been an object of this work to devise a method which will allow the corrosion engineer to select the best inhibitor for a specific environment under field conditions. The test would of necessity be rapid and inexpensive. It would preferably eliminate the need for expensive and delicate instruments.
Pore-Level Observation of Gravity-Assisted Tertiary Gas-Injection Processes
Authors: Ren W. , Bentsen R. , Cunha L. B.
Published: December 2007

In waterdrive oil reservoirs, more than half the initial oil in place (IOIP) is trapped in the water-contacted zone after natural water influx or waterflooding. Gas injection into such reservoirs, with the assistance of gravity, interfacial tension, and oil-film flow, can cause the displacement of excess water and the redistribution of reservoir fluids in the pore space. As the result of such fluid redistribution, most of the residual oil can be recovered. Moreover, a second waterflood following the gas injection can recover the oil in a shorter period of time.

Gravity-assisted tertiary gas-injection processes include the double-displacement process (DDP) and the second-contact water-displacement (SCWD) process. The DDP consists of injecting gas into waterflooded oil zones. The SCWD process consists of submitting these gasflooded zones to a new water-displacement process. In this work, the DDP and the SCWD process were conducted in a transparent sandpack micromodel, and a pore-level observation was performed to investigate the microscopic mechanisms of the two processes.

Observation of the two processes confirmed that the oil films play a very important role in achieving high recovery efficiencies in the DDP. The oil film was seen clearly; such observation also showed that oil flowing through oil films and layers was driven not only by its own weight but also by the increasing volume of the gas. In the SCWD process, trapped gas reduces the possibility of the residual oil being trapped in the center of the pores. Consequently, residual oil can be recovered quickly by a second water-flood. Therefore, the SCWD process is suitable to apply in situations in which the source of gas is not sufficient and in which the formation has a high irreducible gas saturation.
The Transfer of Through-Tubing Drilling Technology Between Provinces
Authors: Morrison John W.
Published: December 2007

Many companies operate on a global basis. Often, a new idea or technology can make a step change in the economics or performance in a particular province or field. That leaves the company with the enviable problem of understanding how and where it could impact operations in other areas of the world.

One area in which BP has had such success is in the North lope of Alaska, where through-tubing drilling (TTD) has made a dramatic impact on their infill-drilling program. In fact, Alaska had developed two distinct TTD techniques—coiled-tubing drilling (CTD) and through-tubing rotary drilling (TTRD). This paper discusses how the technology was transferred to the North Sea. The subject is tackled on three levels:

Transfer of practical knowledge. Tactical choice on the optimum technique. Determination of the strategic value of the technology.

This paper illustrates what needs to be done to ensure a successful business outcome when trying to gain the benefits of a new technology in a different operating environment.

To illustrate the issues, this paper presents performance information on both TTD techniques used in Alaska, discussing their differences and why the application of CTD, in particular, has made such a significant impact. It then discusses how the North Sea's operating environment differs from the North Slope, how this influenced the choice of technology, and the potential magnitude of the benefit that could be realized.

By the end of the analysis, it became clear that the solution and strategy for the North Sea had to be different from that of Alaska, and it became apparent why CTD has struggled to make an impact in the North Sea.
Marlin Failure Analysis and Redesign: Part 3—VIT Completion With Real-Time Monitoring
Authors: Gosch S. W. , Horne D. J. , Pattillo P. D. , Sharp J. W. , Shah P. C.
Published: December 2007

The redesign solution for the batch-drilled wells remaining after the deformation of the Marlin Well A-2 production tieback and tubing was vacuum-insulated tubing (VIT). VIT implementation, however, required a number of computational and experimental innovations.

To ensure well survival, a distributed temperature-monitoring system was developed and evaluated during full-scale VIT testing. Fiber-optic cable run on completions continuously monitors the production-annulus temperature profile. The monitoring system has also proved to be a valuable quality-assurance measure for special annular gels used to minimize conduction and natural convection in the production annulus.

Following the failure of the initial well in the Marlin field,1 the preferred solution for completing the remaining wells was to control wellbore temperature by means of VIT.2 Implementation of VIT required a number of computational and experimental innovations, including:

Provision for insulating the tubing couplings, the source of up to 90% of VIT heat loss. Detailed flow-loop temperature profiles with both axial and radial probes traversing the annulus outside the VIT. These profiles supplemented the conventional values of the overall heat-transfer coefficient and thermal conductivity obtained from the flow-loop measurements. VIT performance, as measured experimentally, must exceed both thermal and mechanical design bases.

Because well survival depends on proper VIT performance, a distributed temperature-monitoring system was developed and evaluated during full-scale testing. On the Marlin tension-leg platform (TLP), fiber-optic cable is run in each well along the length of the VIT to monitor the production-annulus temperature profile continuously. A software system was also developed to feed binary fiber data to an integrated thermal-simulator casing-design software package that calculates safety factors for the B and C annuli. These real-time safety factors interface with the platform alarm system and are continually monitored by operators. If a low safety factor is calculated, a well will be shut in. In addition to feeding the platform alarm system, the software provides data to a web-based plotting program. If a single VIT joint loses its insulating properties, this specific joint can be identified, and appropriate action can be taken. The monitoring system has also proved to be a valuable quality-assurance measure for special annular gels used to minimize conduction and natural convection in the production annulus.

This paper focuses on the value of the combined VIT and fiber/software monitoring system as a means of both controlling and observing well thermal behavior. Typical temperature vs. depth curves are used to illustrate the detailed information retrieved.
Pressure Buildup Analysis of Geothermal Steam Wells With a Parallelepiped Model
Authors: Economides Michael J. , Ogbe David , Miller Frank A. , Cinco-Ley Heber , Fehlberg Eric L.
Published: December 2007

Geothermal well testing, a discipline that evolved from conventional oil and gas well testing, often requires special considerations. The geometry of the reservoir and those characteristics frequently found in geothermal systems engendered the idea of a parallelepiped model with interpenetrating fractures. Such geometry can be described mathematically using Green's and source functions. Equations of reservoir pressure behavior then can be developed for both drawdown and buildup tests. Graphs describing dimensionless pressure as a function of time and various reservoir parameters are provided in this paper. The general method used is type-curve matching.

Introduction

There are three major types of geothermal resources:(vapor-dominated (dry-steam) such as in The Geysers (CA) or in Tuscany of central Italy,two-phase such as in New Zealand, andhot-water, found in several locations.

The most useful, in terms of power production, are the vapor-dominated reservoirs. They are also the most rare. A number of geothermal reservoirs exhibit transient pressure behavior that indicates large, highly conductive fractures. The size of these reservoirs is controlled by faults and overlying impermeable rocks. A constant-pressure boundary, presumably boiling water, often is observed.

A parallelepiped model conceptually could approximate such a configuration. A model with closed, no-flow boundaries on five sides and a constant-pressure boundary on the bottom was described by Cinco-Ley et al. The fracture system was simulated as a rectangular-shaped source. The concept is limited to vapor-dominated reservoirs. Both geologic evidence and production histories have precluded the use of radial models in both The Geysers and Larderello, Italy. Hence, the parallelepiped model, with the included fracture and subformation boiling front, is intended to analyze pressure transient behavior in dry-steam geothermal wells.

Model Description

The model assumes constant-flow-rate production in an anisotropic, homogeneous reservoir. If the flow rate vases, an influence function such as that described by Economides et al. can be used in the subsequent type-curve matching. The reservoir described by the model contains a slightly compressible fluid of constant viscosity and compressibility c. an assumption totally inadequate in the case of geothermal steam. Yet the shortcomings can be overcome if the pseudopressure function m(p) is used. The real-gas pseudopressure was discussed by Al-Hussainy and Ramey. All of these assumptions normally are used in geothermal well testing, irrespective of the model. Although the solution can be modified to incorporate fracture(s) anywhere in the reservoir, a vertical, partially penetrating fracture has been used. The fracture is in the center of a parallelepiped reservoir of square horizontal cross section.

JPT

P. 925^
Equation of State of a Complex Fluid Column and Prediction of Contacts in Orocual Field, Venezuela
Authors: Smith Richard W. , Bard Wade A. , Guerini Agostino , Lugo Claudia , Yemez Ivan
Published: December 2007

The Orocual field is located in the northern Monagas state of Venezuela and is owned and operated by Petroleos de Venezuela S.A. (PDVSA), the national oil company of Venezuela.

Reservoir compartmentalization adds complexity to the field, and structurally equivalent, noncommunicating fluid regions exist. An equation of state (EOS) is needed for reservoir modeling, requiring a review of available data and area fluid distributions.

A seven-pseudocomponent EOS with a single characterization defining the compositional gradient of the hydrocarbon column from gas to black oil is defined. The method demonstrates that composition relative to depth can be predicted in those parts of the reservoir in which samples do not exist but in which production and test data must be matched, and thus where a gas-to-oil transition occurs.

This paper demonstrates a technique to identify representative samples for use in developing an EOS and for initializing fluids in place. A method is presented to adjust the component composition vs. depth, providing consistent vertical composition distribution and compositional-model stability. This method meets the objectives of matching field production observations. A method is presented to quickly initialize a full-field model using a 1D compositional simulator to give full-field-model stability using the local high-temperature gradient.

Results of compositional simulation show a single EOS, and vertical compositional and thermal variation reproduce the complex character of the field hydrocarbon column, matching field-measured observations of saturation pressure (ps), gas/oil ratio (GOR), and fluid densities.
Three-Phase Displacement Theory: An Improved Description of Relative Permeabilities
Authors: Juanes Ruben , Patzek Tad W.
Published: December 2007

In this paper, we revisit the displacement theory of three-phase flow and provide conditions for a relative permeability model to be physical anywhere in the saturation triangle. When capillarity is ignored, most relative permeability functions used today yield regions in the saturation space where the system of equations is locally elliptic, instead of hyperbolic. We are of the opinion that this behavior is not physical, and we identify necessary conditions that relative permeabilities must obey to preserve strict hyperbolicity. These conditions are in agreement with experimental observations and pore-scale physics.

We also present a general analytical solution to the Riemann problem (constant initial and injected states) for three-phase flow, when the system satisfies certain physical conditions that are natural extensions of the two-phase flow case. We describe the characteristic waves that may arise, concluding that only nine combinations of rarefactions, shocks, and rarefaction-shocks are possible. Some of these wave combinations may have been overlooked but can potentially be important in certain recovery processes.

The analytical developments presented here will be useful in the planning and interpretation of three-phase displacement experiments, in the formulation of consistent relative permeability models, and in the implementation of streamline simulators.
Shaybah-220: A Maximum-Reservoir-Contact (MRC) Well and Its Implications for Developing Tight-Facies Reservoirs
Authors: Saleri N. G. , Salamy S. P. , Mubarak H. K. , Sadler R. K. , Dossary A. S. , Muraikhi A. J.
Published: December 2007

This paper presents drilling, completion, well-performance, and reservoir-characterization results of a recently drilled maximum-reservoir-contact (MRC) well in the Shaybah field with a total of eight laterals and an aggregate reservoir contact of 12.3 km (7.6 miles). The well was drilled as part of a pilot program to evaluate both the practical challenges and the reservoir performance impact of MRC wells.

The results to date on eight MRC wells in Shaybah indicate significant sustainable gains in well productivities as well as reductions in unit-development costs. A useful byproduct of MRC drilling is the enhancement achieved in reservoir characterization. These benefits point to MRC wells as disruptive technologies (DTs)1,2 that have positive implications for developing tight-facies reservoirs.
Subsea Development of Shallow, Low-Pressure Gas Reservoirs With High-Performance Well Designs
Authors: Burton R. C. , Davis E. R. , Hodge R. M. , Gilbert T. , Stomp R. , Abdelmalek N. , Bailey M.
Published: December 2007

In the summer of 2000, ConocoPhillips began a program to develop a series of shallow, low-pressure gas reservoirs in the Indonesian waters of the west Natuna Sea. The project consists of a series of subsea wells linked by pipeline to a central mobile gas-processing and -compression unit that feeds a sales line to Singapore. The overall project life is 20 years and will require developing eight small fields with reserves on the order of 1 trillion scf gas.

Initial project planning used conventional well designs to deliver rates on the order of 20 MMscf/D/well from a number of gas reservoirs. This type of well productivity required 10 wells to meet ConocoPhillips Indonesia's maximum contract supply rate, with several wells allocated to each reservoir. To improve project economics, a reduced well count employing high-performance completion designs was developed. The high-performance completions were designed to provide flow rates on the order of 100 MMscf/D at initial reservoir pressures ranging from 1,250 to 1,900 psi. These flow rates allowed well counts to be reduced to one well per reservoir.

This paper will review ConocoPhillips's methodology for design and implementation of the first four high-performance completions in the west Natuna Sea gas project. Well deliverability and initial project results are discussed.
Study of Vuggy Carbonates Using NMR and X-Ray CT Scanning
Authors: Hidajat I. , Mohanty K. K. , Flaum M. , Hirasaki G.
Published: December 2007

Most existing nuclear magnetic resonance (NMR) permeability correlations for carbonates assume that vugs do not contribute to permeability. The objective of this work is to improve permeability estimation from NMR responses for carbonates by including vug connectivity. Six carbonate samples from a west Texas field were studied. NMR T2 measurement, mercury porosimetry, thin-section imaging [using optical microscopy and a scanning electron microscope (SEM)], computerized tomography (CT) scanning, and electrical measurements were conducted. The permeability of the samples studied is controlled by the channels that connect vugs. Capillary pressure and NMR T2 measurements show multimodal pore-throat and pore-body-size distributions. A modified Chang model, which includes the tortuosity factor, is proposed and proven to yield a better permeability prediction than the original Chang model. It is also shown that for the samples studied, the tortuosity can be estimated from NMR T2 distribution, hence allowing permeability prediction from the NMR T2 distribution alone.
Filtration Properties of Oil-in-Water Emulsions Containing Solids
Authors: Al-Riyamy Kassim , Sharma Mukul M.
Published: December 2007

This paper describes a laboratory study of the factors controlling the filtration and fluid-leakoff properties of emulsions containing solid particles. Such fluids are sometimes used as low-leakoff completion fluids.

High-pressure/high-temperature (HP/HT) filtration tests clearly demonstrate that emulsions have the ability to reduce filtrate loss to the formation. However, the emulsion droplets tend to invade the formation and form an internal filter cake. This is evident from the liftoff pressures needed to initiate flowback and deep invasion of emulsion droplets in long-core experiments. Emulsions containing solids (CaCO3, in our case) had lower filtrate volume and higher return permeabilities than solids-free fluids. The effects of percent oil, filtration pressure, core permeability, temperature, and viscosity of the continuous phase were investigated. Filtration pressure and core permeability had major influences on the filtration properties of the emulsified completion fluids. Higher injection pressures increased internal damage and lowered the return permeability. Higher-permeability cores had higher filtrate loss. Emulsion droplets were observed in the effluent, and solid particles are needed to form a stable external filter cake.

Long-core experiments showed that using emulsions containing acid-soluble solid particles have 100% return permeability after an acid squeeze, showing that the emulsion-droplet invasion depth is less than 1 in. It is shown that solids-free fluids had the highest formation damage and higher liftoff pressures.

Analysis of the fluid-leakoff data indicates that emulsions containing solids do not behave as classical filtration theory predicts because of the invasion of emulsion droplets into the formation.

Sizing the solid particles and emulsion droplets in completion fluids and muds according to the permeability of the rock is important in forming stable external filter cakes. This increases the return permeability and results in easier cake removal (low liftoff pressures).
The Use of Real-Time and Time-Lapse Logging-While-Drilling Images for Geosteering and Formation Evaluation in the Breitbrunn Field, Bavaria, Germany
Authors: Rohler Hendrik , Bornemann Ted , Darquin Alexis , Rasmus John
Published: December 2007

Six horizontal wells were drilled into the Tertiary Chatt Sand reservoir of the Breitbrunn gas field in Bavaria, Germany. The purpose of this campaign was to develop part of the depleted reservoir into a gas-storage sand. A detailed geological and petro-physical study was prepared before drilling and resulted in the identification of high-quality reservoir layers that were targeted by the horizontal wells. Despite the simple anticline structure of the field, geometric drilling was ruled out because of remaining geological and directional uncertainties. The geosteering approach adopted relies on real-time resistivity-at-bit images, which were used for the first time during this drilling campaign. The image data are compressed downhole and transmitted to the acquisition computer on the rig, where they are decompressed and analyzed. The images allow the precise placement of the borehole relative to the geology. Layer heterogeneity such as tight streaks, concretions, or patchy porosity can be identified as such and is not interpreted as a different layer entered by the hole, which would lead to a wrong geosteering decision. Logging-while-drilling (LWD) azimuthal data are acquired during drilling and during washdown passes that follow a bit change. A comparison of these time-lapse data sets can provide invasion profiles through time and around the borehole.
Reaction Kinetics of In-Situ Combustion: Part 1—Observations
Authors: Fassihi Mohammad Reza , Brigham William E. , Ramey Henry J.
Published: December 2007

Continuous analysis of produced gases from a small packed bed reactor, at both isothermal and linearly increasing temperatures, has shown that combustion of crude oil in porous media follows several consecutive reactions. Molar carbon dioxide/carbon monoxide (CO2/CO) and apparent hydrogen/carbon (H/C) ratios were used to observe the transition between these reactions at different temperature levels.

A new kinetic model for oxidation of crude oil in porous media is presented in Part 2 of this paper (Page 408).
Chemical Characterization Problems of Water-Soluble Polymers
Authors: Tyssee D. A. , Vetter O. J.
Published: December 2007

Water-soluble polymers are being used increasingly in oil, gas, and geothermal production. Applications include drilling, stimulation, workover and completion, and reservoir flooding fluids. The development of polymers and their application has been mostly empirical. Such a course of development was suitable in the past. However, empirical techniques do not satisfy present and future needs which include (1) the cost/performance relationship and (2) environmental effects associated with expanding polymer application. Therefore, a more thorough understanding of the polymer chemistry is required.

The first step in doing this is to develop laboratory methods to characterize these complex materials and their degradation products. The problems are (1) understanding polymer chemistry under field conditions and (2) developing analytical procedures. These problems emerged dramatically during analysis of recent fracture stimulation of some geothermal wells. An involved study of the potential analytical methods was conducted. Polysaccharides were used for the actual field fracture jobs as well as for the analytical procedures. Correlations were made between the total organic content and carbohydrate content of the return waters as a function of residence time under simulated reservoir conditions. Preliminary indications are that more sophisticated information can be obtained by the use of emerging analytical techniques such as high pressure liquid chromatography (HPLC).

Advantages gained from use of these methods and others are discussed.
Prediction of Viscosity for Partially Hydrolyzed Polyacrylamide Solutions in the Presence of Calcium and Magnesium Ions
Authors: Ward J. S. , Martin F. David
Published: December 2007

Loss of solution viscosity in water of increasing ionic strength is a major problem encountered in the use of the partially hydrolyzed polyacrylamide polymers for improved oil recovery. It is recognized widely that the viscosity loss is more drastic in the presence of multivalent cations than is observed for sodium ions. There is, however, little information available on the relationships between total ionic strength, concentrations of multivalent cations, and solution viscosities.

The purpose of this study is to establish relationships between total ionic strength, concentration of calcium or magnesium ions, polymer concentration, and the resulting viscosity for partially hydrolyzed polyacrylamides with varying degrees of hydrolysis. Solutions at constant ionic strength with varying ratios of calcium or magnesium to sodium ions are compared, and the loss of viscosity as a function of the fraction of divalent cations in the system is determined. For shear rates in the power-law region, the fractional loss in viscosity is a function of the fraction of multivalent cations and, in the range studied, is independent of the total ionic strength. A more complicated relationship is found at lower shear rates where the fractional viscosity loss does vary with total ionic strength.

The relationship in the power-law region should prove valuable in predicting viscosities on the basis of the dependence of viscosity on ionic strength and on multivalent cation concentration at a single ionic strength, eliminating the need for many individual measurements of viscosity. More work is needed before useful predictions will be possible at lower shear rates.
Phase Behavior and Properties of a Petroleum Sulfonate Blend
Authors: Bae J. H. , Petrick C. B.
Published: December 2007

A sulfonate system composed of Stepan Petrostep™ 465, Petrostep 420, and 1-pentanol was investigated. The system was found to give ultralow interfacial tension against crude oil in a reasonable range of salinity and sulfonate concentrations. It also was found that sulfonate partitioned predominantly into the microemulsion phase. However, a significant amount also partitioned into water and, at high salinity, into the oil phase. On the other hand, the oil-soluble 1-pentanol partitioned mostly into oil and microemulsion phases.

The interfacial tension between excess oil and water phases was ultralow, in the range of 10−3 mN/m. The tensions were close to and paralleled those between the middle and water phases. The trend remained the same even when the alcohol content changed. This means that in the salinity range that produces a three-phase region, below the optimal salinity, the water phase effectively displaces both oil and middle phases, even though the oil may not be displaced effectively by the middle phase. The implication is that, from an interfacial tension point of view, the oil recovery would be more favorable in the salinity range below the optimal salinity with the mixed petroleum sulfonate system used here. This was confirmed by oil recovery tests in Berea cores. It also was concluded that the change in viscosity upon microemulsion formation might have a significant influence on the surfactant flood performance.
A Chemical Theory for Linear Alkaline Flooding
Authors: deZabala E. F. , Vislocky J. M. , Rubin E. , Radke C. J.
Published: December 2007

A simple equilibrium chemical model is presented for continuous, linear, alkaline waterflooding of acid oils. The unique feature of the theory is that the chemistry of the acid hydrolysis to produce surfactants is included, but only for a single acid species. The in-situ produced surfactant is presumed to alter the oil/water fractional flow curves depending on its local concentration. Alkali adsorption lag is accounted for by base ion exchange with the reservoir rock. The effect of varying acid number, mobility ratio, and injected pH is investigated for secondary and tertiary alkaline flooding.

Since the surface-active agent is produced in situ, a continuous alkaline flood behaves similar to a displacement with a surfactant pulse. This surfactant-pulse behavior strands otherwise mobile oil. It also leads to delayed and reduced enhanced oil recovery for adverse mobility ratios, especially in the tertiary mode. Caustic ion exchange significantly delays enhanced oil production at low injected pH.

New, experimental tertiary caustic displacements are presented for Ranger-zone oil in Wilmington sands. Tertiary oil recovery is observed once mobility control is established. Qualitative agreement is found between the chemical displacement model and the experimental displacement results.
Modeling of a Micellar/Polymer Process
Authors: Bang Hwi W. , Caudle Ben H.
Published: December 2007

A highly implicit, multidimensional, multicomponent, multiphase, unsteady-state flow model has been formulated to simulate a micellar/polymer process. Unlike most compositional approaches, the proposed model accounts for capillary pressure. In addition, the model describes the unsteady-state flow of fluids and accounts for additional pressure- and concentration-dependent variables such as average mass velocity, effective dispersivity, and FVF that most compositional models do not. Numerical solutions to this model are obtained by a finite-difference method. For a one-dimensional (ID) case, the system is treated in terms of five pseudocomponents and two mobile phases. The proposed model is represented by a system of nonlinear partial differential equations in the dependent variables, component concentrations, and phase pressures. The model incorporates the process variables. These include those mentioned above plus interfacial tension (IFT), relative permeability, partition coefficient, adsorption concentration, and viscosity. The model was validated by history-matching with a laboratory core displacement test. The agreement of the numerical results and laboratory results shows the model's reliability and gives a realistic insight into its usefulness as a multidimensional, multicomponent, multiphase simulator. After testing, the model was used to investigate the effect of variations in the input parameters on the production history.
Effect of Burial History on the Subsurface Horizontal Stresses of Formations Having Different Material Properties
Authors: Prats M.
Published: December 2007

Although current mechanical properties of formations may provide rough estimates of subsurface horizontal stresses, they are inadequate to ascertain which of two adjacent formations has the higher horizontal stress. Temperatures, creep, and changes in material properties and strain during burial have a significant influence on today's state of stress.
Xanthan Gum—A Lyotropic, Liquid Crystalline Polymer and its Properties as a Suspending Agent
Authors: Salamone J. C. , Clough S. B. , Salamone A. Beal , Reid K. I. G. , Jamison D. E.
Published: December 2007

A variety of polysaccharides have been used in drilling fluids,1–4 and some of these polymers have been studied in tertiary recovery. Of particular interest in both these areas has been xanthan gum, the extracellular polysaccharide produced by Xanthomonas campestris, because of its relatively stable viscosity properties as a function of salt concentration, pH, temperature, and shear degradation. Indeed, no synthetic polymer or any other commercially available, naturally occurring polymer, or polymer derivative has been able to duplicate the solution behavior of xanthan gum.

During a study of xanthan gum's ability to suspend barium sulfate, it appeared that xanthan gum in aqueous solution at relatively low concentrations could have lyotropic liquid crystalline behavior. Behavior of this type has been noted for other biopolymers5 and recently has been demonstrated for various cellulose derivatives.6–10 An anisotropically ordered polymer solution would be extremely difficult to reproduce synthetically but could explain most of the unique properties of xanthan solutions.

To test the possibility that xanthan gum could have liquid crystalline order, a variety of xanthan solutions of various polymer concentrations in the presence and absence of various salts were studied under a polarized light microscope (100X). With solutions from 2 to 10% (wt/vol) xanthan gum in distilled water at room temperature, birefringent, ordered domains were observed at 10% concentration, with a decrease in birefringence as the polymer concentration decreased. At 2% concentration, no birefringence was observed, indicating the apparent area of change from an isotropic to an anisotropic phase. This point appears to occur at 2.9% by optical determination. In fact, this value could be considerably lower as revealed by other techniques for anisotropic xanthan solutions.8–10 For the 10% solution of xanthan gum, heating in a roller oven at 150°F (66°C) for 2 hours did not diminish the birefringence. Similarly, when a 10% xanthan gum solution was prepared in 10% KCI and in 33% CaCl2 solutions, birefringence was not decreased.