bluuebunny/crossref_metadata_2025 huggingface dataset:
New Techniques for Oriented-Density Evaluation
Authors: Holm A.E. , Kleinegger J.
Published: December 2007

By using a digital readout panel, a quantitative evaluation of the densities surrounding casing strings was made with a motorized oriented-density tool. Subsequent drilling-out alongside the casing confirmed the log evaluation.

Introduction

Since earlier tools could give only a qualitative evaluation of the densities surrounding the casing, a digital readout panel with some electronic modifications was used with the motorized oriented-density tool. This tool now can be used to quantitatively evaluate the wellbore and to orient perforations in dual or multiple casing-string wells.

A simulated-well calibrator was built to calibrate the oriented-density tool while looking through neat cement. Correlation of the calibrator with the actual well logs was excellent. The effective depth of investigation of this tool was also determined using the simulated-well calibrator.

Hypothesis

By plotting tool counts per second vs bulk density, this tool can detect other casing strings, neat cement, pozmix cement, mud, water, and gas with reliable results.

Well Conditions Used

Casing: 2 7/8-in., 6.4-lb, J-55, NU, 10 round tubing; two strings cemented nonconcentrically in an 8 3/4-in. wellbore using rubber turbilizers.

Completion cement: Class B neat cement mixed at 15.6 ppg; 1.96-gm/cc bulk density when set up; pumped as tail-in slurry.

Filler cement: 65/35 Class B pozmix cement with 12-percent get added; mixed with 15.56 gal of water per sack at 11.3 ppg; 1.48-gm/cc bulk density when set up; pumped as lead-in slurry. pumped as lead-in slurry. Motorized oriented-density tool: 1-11/16-in.-OD collar locator and motor sections above a 2 1/8-in.-OD window-type detector and radioactive source sections, which can be installed above a 2-in. cased gun for oriented perforating (Fig. 1).

Tool Calibration Simulated-Well Calibrator

To accurately determine the response to neat cement, a calibrator was built to simulate a single string of 2 7/8-in. casing cemented in a wellbore with neat cement. The calibrator is a 14 1/2-in.-ID, 36.71-lb, Grade B line pipe with a pup joint of 2 7/8-in., 6.4-lb, J-55 tubing capped on the bottom end and cemented adjacent to the inner wall of the line pipe. The 2 7/8-in. tubing was then filled with water (Fig. 2).

Calibrator Results

A 5-counts/sec statistical variation resulted. Logging was performed without tool rotation; then the detector performed without tool rotation; then the detector window was placed looking directly toward the neat cement (180 degrees) and was recorded on the chart. An average 115 counts/sec was recorded. with an over-all statistical variation of 5 counts/sec.

The effective depth of investigation was 4.5 in. Logging with tool rotation in the calibrator, a sweep of 154 degrees was observed in the neat cement before encountering the 14 1/2-in. line pipe (Fig. 3).

JPT

P. 1151
Convection in Fractured Reservoirs - The Effect of Matrix-Fissure Transfer on the Instability of a Density Inversion in a Vertical Fissure
Authors: Peaceman D.W.
Published: December 2007

In a fractured reservoir undergoing pressure depletion, evolution of gas at the top of the oil zone leads to an unstable density inversion in the fissures. The resulting convection brings heavy oil into contact with matrix blocks containing light oil, and results in the transfer of dissolved gas between matrix and fissure in the undersaturated region of the oil zone. To provide a better understanding of dis process, an earlier perturbation analysis of a density inversion in a vertical fissure has been extended to include the matrix-assure transfer.

It was found that matrix-fissure transfer does not affect the stability or instability of a density inversion, nor does it affect the spacing of density angers or the size of convection cells. A quantitative expression for the rate of growth of unstable density fingers was derived. The effect of matrix-fissure transfer is always to reduce the rate of growth. For practical reservoir cases, while any density inversion should be highly unstable, matrix-fissure transfer can be expected to cause a significant reduction in the linger growth rate.

Introduction

Most fractured reservoirs of commercial interest are characterized by the existence of a system of high-conductivity fissures together with a large number of matrix blocks containing most of the oil. It has been recognized for some time that the analysis of the behavior of a fractured reservoir must involve an understanding of the performance of single matrix blocks under the various environmental conditions that can exist in the fissures. However, only recently has it been recognized that a similar need exists for a better understanding of the convective mixing that probably takes place within the oil-filled portion of the fissure system.

In a fractured reservoir undergoing pressure depletion, gas will be evolved at all points of the reservoir where the oil pressure has declined below the original saturation pressure. This depth interval is referred to as the gassing zone. Because of the high conductivity of the fracture, the gas in the fissures will segregate rapidly from the oil before reaching the producing wells and most, if not all, of it will join the expanding gas cap.

At a sufficient depth, however, the oil pressure will still be higher than the saturation pressure, and the oil there remains in an undersaturated condition. (See Fig. 1.)

In the gassing zone, gas evolves from the oil in both the fissures and the matrix. The oil left behind in the fissures within the gassing zone contains less dissolved gas and is heavier than the oil below it in the undersaturated zone.

SPEJ

P. 269
Programming Reservoir Problems on the Electric Analyzer
Authors: Barrett Mary , Rose Walter
Published: December 2007

Introduction

The conventional way to program reservoir problems for solution on the electric analyzer is one which concentrates the block units towards the inner radius of the prototype system being represented by the analog model.

Present Programming Method

While this conventional way of programming problems is quite adequate for routine uses of the electric analyzer, it leads to difficulties in those cases where the inner radius of the prototype system (e.g., the wellbore) is small compared to the external radius (e.g., the external reservoir boundary). To handle such a case by the conventional method would require either that a large value be selected for the constant a or that a large number n, of radial block units be chosen. In consequence, the capacitance and vertical resistance ratios become impossibly large, as will be evident from the relations, given above. In any event, the size of the smallest and largest capacitors will always be limited by the size of commercially available components, and the analyzer itself will determine how many mesh points are available for radial block units.
A Compositional Material Balance for Combination Drive Reservoirs with Gas and Water Injection
Authors: Lohrenz John , Clark George C.
Published: December 2007

Compositional material balance methods have been extended to solution gas-gas cap-water drive reservoirs. Partial or complete pressure maintenance as well as reservoir repressuring by gas and/or water injection may be considered. Increments of reservoir withdrawals and injections equivalent to a given time increment are used as the basic iterative step to allow the extension. An example field study shows how the reservoir volumes, extent of the water drive, and relative permeability ratio function may be estimated. Knowing these, the methods can be used to predict reservoir behavior.

Introduction

The compositional material balance is similar to conventional material balances in many aspects. The assumption of a pressure-homogenous reservoir with no transients is common to all conventional material balances although numerical methods are different. The compositional material balance also contains this assumption. Inclusion of phase equilibria directly in reservoir calculations is the key difference and improvement in the compositional material balance. A continuous account of the compositions of the reservoir fluids and effluents is determined. Calculations of fluid phases and properties can be based on these compositions. Excepting fluid phases and properties determined in this manner, the compositional material balance uses procedures exactly analogous to conventional methods. Brinkman and Weinaug and Jacoby and Berry have given compositional material balances for simple solution gas drive reservoirs; subsequently Jacoby and Berry, extended their procedure to include pressure maintenance by gas injection at constant reservoir pressure. This paper extends compositional material balance techniques to a more general combination drive reservoir with various types of pressure maintenance operations. The procedure for this extended compositional material balance and an example of its field application are presented.
The Effects of Non-Darcy Flow on the Behavior of Hydraulically Fractured Gas Wells (includes associated paper 6417 )
Authors: Holditch S.A. , Morse R.A.
Published: December 2007

A reservoir simulator modified to include non-Darcy flow and fractureclosure was used to demonstrate the effects of non-Darcy gas flow in ahydraulic fracture on well performance. Results illustrate the effects onthe gas-well productivity index and on the analysis of pressure builduptests.

Introduction

Laminar flow of fluid through porous media can bedescribed using Darcy's law:(1)

This equation indicates that if the resistance (mu/k)remains constant, the pressure gradient (delta p/delta L) isproportional to the velocity of the fluid (v). However, when thevelocity is increased such that the flow is not laminar, thepressure drop will increase more than the proportional increase in velocity.

Fancher et al. recognized this behavior and publisheda paper in 1933 that gave an analogy between the flow offluids through porous media and the flow of fluidsthrough pipe. Several authors, including Brownell andKatz and Tek, have since published methods forpredicting the laminar and turbulent regions of flow inporous media based on correlations similar to the Reynoldsnumber for flow in pipe.

The generalized equation for flow through porousmedia may be represented by the following equationsuggested by Forchheimer.

(2)

If the constant (a) or velocity (i,) approaches zero. thenthe second term can be ignored and Eq. 2 is equal toDarcy's law (Eq. 1).

Cornell and Katz reformulated Eq. 2 as follows:

(3)

In Eq. 3, the constant (a) was replaced by the product ofthe fluid density (rho) and the beta factor, which is acharacteristic of the porous medium. Several authors havepublished empirical correlations of the beta factor with theporosity and permeability of the porous media.

Geertsma pointed out that the analogy betweenlaminar and turbulent flow of fluids in porous media to theflow of fluids in pipes could be misleading. Geertsmastated that turbulence does not actually occur in the smallpore systems of reservoir rock, and the cause of theincreased pressure gradients at high fluid velocities isinertial resistance. Consequently, Geertsma defined theparameter beta as the coefficient of inertial resistance. Geertsma's paper, therefore, has created a bit ofcontroversy concerning the terminology of the parameter betain the Forchheimer equation.

In reality, the excess pressure gradients at high fluidvelocities can be caused by either turbulence or inertialresistance, or by a combination of the two, depending onthe particular pore configuration of the reservoir rockbeing considered. In this paper, the parameter beta isreferred to as the beta factor. Regardless of its name, the beta factoris a value used to calculate the correct pressure gradientsunder nondarcy flow conditions.

Cooke investigated nondarcy flow in packed, hydraulically induced fractures. He noted that beta factors forfractures packed with multiple layers of sand had notbeen reported in the petroleum literature and suggested the following equation for calculating beta factors:

(4)

JPT

P. 1169^
Gel Systems for Controlling CO2 Mobility in Carbon Dioxide Miscible Flooding
Authors: Raje M. , Asghari K. , Vossoughi S. , Green D. W. , Willhite G. P.
Published: December 2007

Conformance control for carbon dioxide miscible flooding using gel has not been widely attempted. Laboratory research efforts at the University of Kansas have produced promising in-situ gelation techniques aimed at this application. Three in-situ gel systems were developed and tested in laboratory cores. Two systems are based on a new biopolymer, termed KUSP1, and the third gel system uses the reaction of sulfomethylated resorcinol and formaldehyde to form a gel.

KUSP1 gel systems were studied using two different methods of inducing in-situ gelation. In the first method, gelation was accomplished by injecting CO2 at low pressure into the Berea sandstone core saturated by alkaline polymer solution. Permeability reduction to the brine and CO2 in the range of 80% was achieved. Stability of the gel was tested in the presence of supercritical CO2. When supercritical CO2 was used to induce in-situ gelation, the same degree of permeability reduction was achieved. The gel remained stable after the injection of many pore volumes of supercritical CO2. The second method of initiating in-situ gelation involved the use of an ester. Hydrolysis of the ester, monoethylphthalate, in the alkaline polymer solution caused the pH to drop to levels where in-situ gelation occurred. The permeability of the treated core to supercritical carbon dioxide was about 1 md which was equivalent to a permeability reduction of 95%–97% of the initial brine permeability.

The third gel system, based on the reaction of sulfomethylated resorcinol and formaldehyde (SMRF), was gelled in situ and contacted with both brine and supercritical CO2. Permeabilities to carbon dioxide on the order of 1 md or less were observed. This permeability is equivalent to a reduction of about 99% in the initial brine permeability. Reduced permeabilities were maintained after injecting many pore volumes of supercritical CO2 and brine.
Applications of a New, Efficient Hydraulic Fracturing Fluid System
Authors: Powell R. J. , McCabe M. A. , Slabaugh B. F. , Terracina J. M. , Yaritz J. G. , Ferrer D.
Published: December 2007

This paper discusses low-temperature applications for an optimized low-gel borate fluid system that does not rely on a separate component to maintain system pH. This fluid system's viscosity, fluid loss, static proppant settling, and dynamic proppant transport were tested; experimental procedures and results are described. Case studies from Argentina, Ecuador, the Texas Panhandle, and Permian Basin are also included.

A new, borate-crosslinked hydraulic fracturing fluid system has been developed. This new, optimized fluid system provides higher viscosity with lower gelling-agent concentrations compared to conventional, borate-crosslinked fluids. Application of the optimized low-gel borate (OLGB) fluid system at low temperatures is discussed. Viscosity, proppant transport, and fluid-loss data of the OLGB fluid system are compared to conventional, borate- crosslinked fracturing fluids. Treatment designs are also presented.
Flow Heterogeneity in Reservoir Rocks
Authors: Rosman A. , Simon R.
Published: December 2007

Introduction

Microscopic flow heterogeneity in reservoir rocks is related to pore size, pore shape, and location of the different pore sizes that determine flow paths of various permeabilities. In this paper, microscopic flow permeabilities. In this paper, microscopic flow heterogeneity is expressed by breakthrough recovery in a nitrogen/helium miscible displacement. Earlier nitrogen breakthrough indicates a higher degree of heterogeneity.

The following sections describe the experimental technique for measuring microscopic flow heterogeneity and give the results of some measurements in sandstones, limestones, and sand packs.

Experimental Technique

The technique involves using nitrogen to displace helium from a core, and measuring nitrogen breakthrough and effluent composition by frontal chromatography methods. These measurements agree well with measurements from liquid, equal-viscosity miscible displacements in the same cores (Table 1).

Nitrogen and helium were chosen because their viscosity ratio approaches unity at room temperature and because they have sufficiently different thermal conductivities for chromatographic detection. The nitrogen/ helium method is simple, rapid, and nondestructive.

Measuring Sequence

The core is mounted vertically (Fig. 1) to avoid gravity segregation effects caused by the density difference between helium and nitrogen. To insure repeatability, the core must be cleaned and dried before beginning the test. A typical run proceeds as follows:The core is saturated with helium.Nitrogen is injected into the bottom of the core. The emerging gas flows through the chromatograph so that nitrogen breakthrough can be detected and timed.Once nitrogen has replaced all helium in the core, the reverse operation can be performed to resaturate with helium injected from the top.

Output

Fig. 2 shows the output of a microscopic flow heterogeneity measurement, with the normal chromatographic output in millivolts and the corresponding percent of nitrogen in the effluent. The zero signal continues as long as only helium flows from the core.

In Fig. 2. nitrogen breakthrough occurs after 12.2 seconds. Increasing nitrogen concentration in the effluent changes the signal.

JPT

P. 1427
Formation-Rate-Analysis Technique: Combined Drawdown and Buildup Analysis for Wireline Formation Test Data
Authors: Kasap Ekrem , Huang Kun , Shwe Than , Georgi Dan
Published: December 2007

The formation-rate-analysis (FRASM) technique is introduced. The technique is based on the calculated formation rate by correcting the piston rate with fluid compressibility. A geometric factor is used to account for irregular flow geometry caused by probe drawdown. The technique focuses on the flow from formation, is applicable to both drawdown and buildup data simultaneously, does not require long buildup periods, and can be implemented with a multilinear regression, from which near-wellbore permeability, p*, and formation fluid compressibility are readily determined. The field data applications indicate that FRA is much less amenable to data quality because it utilizes the entire data set.
Moment-Equation Approach to Single Phase Fluid Flow in Heterogeneous Reservoirs
Authors: Zhang Dongxiao , Winter C. L.
Published: December 2007

In this paper, we study single phase, steady-state flow in bounded, heterogeneous reservoirs. We derive general equations governing the statistical moments of flow quantities by perturbation expansions. These moments may be used to construct confidence intervals for the flow quantities. Due to their mathematical complexity, we solve the moment differential equations (MDEs) by the numerical technique of finite differences. The numerical MDE approach renders the flexibility in handling complex flow configurations, different boundary conditions, various covariance functions of the independent variables, and moderately irregular geometry, all of which are important factors to consider for real-world applications. The other method with these flexibilities is Monte Carlo simulation (MCS) which has been widely used in the industry. These two approaches are complementary, and each has its own advantages and disadvantages. The numerical MDE approach is compared with published results of MCS and analytical MDE approaches and is demonstrated with two examples involving injection/production wells.
Neural Network Model for Estimating the PVT Properties of Middle East Crude Oils
Authors: B.C. Gharbi Ridha , Elsharkawy Adel M.
Published: December 2007

The importance of pressure/volume/temperature (PVT) properties, such as the bubblepoint pressure, solution gas-oil ratio, and oil formation volume factor, makes their accurate determination necessary for reservoir performance calculations. An enormous amount of PVT data has been collected and correlated over many years for different types of hydrocarbon systems. Almost all of these correlations were developed with linear or nonlinear multiple regression or graphical techniques. Artificial neural networks, once successfully trained, offer an alternative way to obtain reliable results for the determination of crude oil PVT properties.

In this study, we present neural-network-based models for the prediction of PVT properties of crude oils from the Middle East. The data on which the network was trained represent the largest data set ever collected to be used in developing PVT models for Middle East crude oils. The neural-network model is able to predict the bubblepoint pressure and the oil formation volume factor as a function of the solution gas-oil ratio, the gas specific gravity, the oil specific gravity, and the temperature. A detailed comparison between the results predicted by the neural-network models and those predicted by other correlations are presented for these Middle East crude-oil samples.
Comparative Effectiveness of CO2, Produced Gas, and Flue Gas for Enhanced Heavy-Oil Recovery
Authors: Srivastava Raj K. , Huang Sam S. , Dong Mingzhe
Published: December 2007

A large number of heavy oil reservoirs in Canada and in other parts of the world are thin and marginal and thus unsuited for thermal recovery methods. Immiscible gas displacement appears to be a very promising enhanced oil recovery technique for these reservoirs. This paper discusses results of a laboratory investigation, including pressure/volume/temperature (PVT) studies and coreflood experiments, for assessing the suitability and effectiveness of three injection gases for heavy-oil recovery. The gases investigated were a flue gas (containing 15 mol % CO2 in N2),a produced gas (containing 15 mol % CO2 in CH4), and pure CO2. The test heavy-oil (14° API gravity) was collected from Senlac reservoir located in the Lloydminster area, Saskatchewan, Canada.

PVT studies indicated that the important mechanism for Senlac oil recovery by gas injection was mainly oil viscosity reduction. Pure CO2 appeared to be the best recovery agent, followed by the produced gas. The coreflood results confirmed these findings. Nevertheless, produced gas and flue gas could be sufficiently effective flooding agents. Comparable oil recoveries in flue gas or produced gas runs were believed to be a combined result of two competing mechanisms—a free-gas mechanism provided by N2 or CH4 and a solubilization mechanism provided by CO2. This latter predominates in CO2 floods.
General Method to Calculate the Permeability Weighting Function for Well Testing in Heterogeneous Media
Authors: Romeu R. K. , Lara A. Q. , Nœtinger Benoît , Renard Gérard
Published: December 2007

The perturbation method provides approximate solutions of the well pressure for arbitrarily heterogeneous media. Although theoretically limited to small permeability variations, this approach has proved to be very useful, providing qualitative understanding and valuable quantitative results for many applications. The well pressure solution using this method is expressed by an integral equation where the permeability variations are weighted by a kernel, the permeability weighting function. As discussed in previous papers, deriving such permeability weighting functions appears to be a complicated calculation, available only for special cases. In this article we present simple and general method to calculate the permeability weighting function. In the Laplace domain, the permeability weighting function is easily related to the pressure solution of the background problem. Since Laplace pressure solutions are known for many situations (various boundary conditions, stratified and composite media etc.), the associated permeability weighting function can be derived immediately. Among other examples, we calculate and discuss the well pressure solution for a horizontal well that is producing from a heterogeneous reservoir.
Wellbore-Stability Predictions by Use of a Modified Lade Criterion
Authors: Ewy R. T.
Published: December 2007

The two most commonly used rock failure criteria in wellbore stability analyses are the Mohr–Coulomb criterion and the Drucker–Prager criterion. Neither of these is compatible with three-dimensional rock strength measurements that have explored the influence of the intermediate principal stress. This paper presents a modified Lade criterion which has the following desirable qualities: 1. it correctly describes the influence of the intermediate stress on rock strength, and therefore on wellbore stability, 2. it can be rearranged to give a closed-form solution for critical mud weight, for any wellbore orientation, and 3. only two rock strength parameters are required, such as cohesion and friction angle. The modified Lade criterion predicts critical mud weight values that are less conservative than those predicted by the Mohr–Coulomb criterion yet are not as unconservative as those predicted by the Drucker–Prager criterion. It also reveals that the required increase in mud weight when going from low hole angle to high hole angle is not as great as predicted by either the Mohr–Coulomb or Drucker–Prager criteria.
Field-Scale and Wellbore Modeling of Compaction-Induced Casing Failures
Authors: Hilbert L. B. , Gwinn R. L. , Moroney T. A. , Deitrick G. L.
Published: December 2007

Presented in this paper are the results and verification of field- and wellbore-scale large deformation, elasto-plastic, geomechanical finite element models of reservoir compaction and associated casing damage. The models were developed as part of a multidisciplinary team project to reduce the number of costly well failures in the diatomite reservoir of the South Belridge Field near Bakers-field, California. Reservoir compaction of high porosity diatomite rock induces localized shearing deformations on horizontal weak-rock layers and geologic unconformities. The localized shearing deformations result in casing damage or failure. Two-dimensional, field-scale finite element models were used to develop relationships between field operations, surface subsidence, and shear-induced casing damage. Pore pressures were computed for eighteen years of simulated production and water injection, using a three-dimensional reservoir simulator. The pore pressures were input to the two-dimensional geomechanical field-scale model. Frictional contact surfaces were used to model localized shear deformations. To capture the complex casing-cement-rock interaction that governs casing damage and failure, three-dimensional models of a wellbore were constructed, including a frictional sliding surface to model localized shear deformation. Calculations were compared to field data for verification of the models.
Pressure-Transient Analysis for Perforated Wells
Authors: Yildiz Turhan , Ozkan Erdal
Published: December 2007

This study presents a three-dimensional analytical model to analyze the transient flow into perforated vertical wells. The model considers arbitrary phasing angle, nonuniform perforation size and length, and formation damage around perforations. The characteristics of transient pressure and derivative responses of perforated wells are investigated. A sensitivity study is carried out to identify the impact of various reservoir and completion parameters on the transient pressure and derivative responses. It is observed that convergent flow into perforations significantly influences the early-time and intermediate-time pressure responses. A pseudoskin expression, which can be used to estimate the inflow performance, is also presented.
A Calculation Method for Carbonated Water Flooding
Authors: De Nevers Noel
Published: December 2007

A calculation method has been developed for carbonated water flooding. This method takes into account the effects of oil viscosity reduction and oil swelling, due to carbon dioxide transferred to the reservoir oil from the carbonated flood water. It shows the effect of changes in carbonation pressure and carbonated water slug size. The method is based on a Buckley-Leverett- type linear flow model. The mathematical approach is similar to that developed by Welge, et al, for enriched gas drives. However, it contains a very important advance over the previous papers in its solution to the problem of injection of a "slug" of carbonated water rather than continuous injection of fluid of constant composition. The method also shows the chromatographic nature of the transport of CO2 in a carbonated water flood. Sample calculations indicate that viscosity reduction is the most important source of incremental oil recovery. Swelling contributes to a lesser extent. Raising the carbonation pressure increases recovery, but this effect diminishes as pressure is increased. Increasing the slug size also increases recovery, but again this effect diminishes as slug size is increased.

Introduction

In recent years there has been considerable interest in carbonated water flooding as a secondary recovery method. Several carbonated waterflood field tests are now in progress. Yet there is no published method for predicting the results of a carbonated water flood. This paper presents a method for predicting the oil recovery for a carbonated water flood.In a carbonated water flood, a carbonated water slug is injected into the reservoir. Then this slug is driven forward by injecting plain water behind it. The field operator must choose the carbonated water slug size and the CO2:water ratio in the slug. The calculation method presented here shows the effects of both slug size and CO2:water ratio on oil recovery.
Calculation of Wellbore Pressures and Rate Distribution in Multilayered Reservoirs
Authors: Prats Michael , Vogiatzis J. P.
Published: December 2007

An analytic procedure in Laplace space is developed to calculate the wellbore pressure and rate distribution, and their time rate of change, in anisotropic multilayer formations with axial symmetry and interlayer crossflow, in the presence of skins and wellbore storage, for any number of layers, any number of intervals open to the formation, for wells of nonzero radius, for finite external radii, and for no flow at the outer boundaries. Numerically, the procedure appears to be robust and trouble free. A number of applications to which the procedure can meaningfully be used are identified, and some elements of the procedure are illustrated through two brief examples.
Investigating the Role of Crude-Oil Components on Wettability Alteration Using Atomic Force Microscopy
Authors: Basu Subhayu , M. Sharma Mukul
Published: December 2007

The surface forces between a crude-oil and its components (oil, resin, and asphaltenes) and a glass substrate have been measured in brine of different salinity and pH using an atomic force microscope. The force vs. distance curves are used to measure the critical disjoining pressure for wettability alteration, i.e., departure from water-wet conditions. The measured data are compared with the classical DLVO theory to explore the nature of interaction of these components with mineral substrates.

The results indicate that the resins and asphaltenes obey the DLVO theory, i.e., the stability of the brine film decreases with increasing brine salinity and increases with increasing solution pH. The opposite trend is observed with increasing salinity for the nonpolar (pentane soluble) fraction and for the crude oil itself. The deviation from DLVO predictions indicates that for nonpolar oils, hydrophobic interactions may play an important role in the interaction of oils with minerals and, therefore, in wettability reversal.
Flow Simulation of Geologic Models
Authors: King M. J. , Mansfield Mark
Published: December 2007

We report upon our experience in performing flow simulation within detailed three dimensional geologic models. Such models have the potential to significantly improve mechanistic understanding of fluid flow through our reservoirs, especially those influenced by strong contrasts in permeability at multiple scales. We have found that utilizing these static models in a dynamic sense places new requirements upon the models, and forces a reevalua-tion of the theoretical foundations behind our flow simulators. We review a range of physical and numerical concepts, and provide the required conceptual extensions and new derivations.
Practical Use of Scale Up and Parallel Reservoir Simulation Technologies in Field Studies
Authors: Tchelepi H. A. , Durlofsky L. J. , Chen W. H. , Bernath A. , Chien M. C. H.
Published: December 2007

Scale up and parallel reservoir simulation represent two distinct approaches for the simulation of highly detailed geological or geostatistical reservoir models. In this paper, we discuss the complementary use of these two approaches for practical, large scale reservoir simulation problems. We first review our recently developed approaches for upscaling and parallel reservoir simulation. Then, several practical large scale modeling problems, which include simulations of multiple realizations of a waterflood pattern element, a four well sector model, and a large, 130 well segment model, are addressed. It is shown that, for the pattern waterflood model, significantly coarsened models provide reliable results for many aspects of the reservoir flow. However, the simulation of at least some of the fine scale geostatistical realizations, accomplished using our parallel reservoir simulation technology, is useful in determining the appropriate level of scale up. For models with a large number of wells, the upscaled models can lose accuracy as the grid is coarsened. In these cases, although field-wide performance can still be predicted with reasonable accuracy, parallel reservoir simulation is required to maintain sufficiently refined models capable of accurate flow results on a well by well basis. Finally, some issues concerning the use of highly detailed models in practical simulation studies are discussed.
The New Law for California's Offshore Oil Development
Authors: Moroney Thomas C.
Published: December 2007

Introduction

It is the purpose of this article to demonstrate the significance of the new law for California's offshore oil development; to explain its provisions; to praise and criticize it; to emphasize the responsibility of the petroleum industry in operating under it; and to offer some speculative comments.

Necessity for New State Law

Previous Inadequacy of Law

The people of California for six years waged a battle which was successfully culminated by the enactment of federal legislation in 1953 whereby Congress confirmed California's claim to ownership of the 3-mile submerged land belt lying offshore the coast of the state. During those six years, the people of the state had made two things clearthat they were attacking the philosophy of the Supreme Court, andthat the unwarranted expropriation by judicial decision of the state's oil resources and other property rights in the submerged land area was a matter for great alarm.

For nearly 2 1/2 years after the restoration of those rights, the State of California was still unable to permit the proper exploration and development of the oil and gas resources underlying that belt because of the inadequacy of the state's then existing law. What a strange predicament after such a long period during which public officials and private persons represented to the Congress and to the people of the nation that, among other things, we needed our tide and submerged lands in order to explore and develop them for oil and natural gas, not only to provide for civilian uses in peacetime, but for the protection of our country in time of war.

To Keep Faith With Congress

It was essential that California laws be amended to provide for the exploration and development of our petroleum resources in the ocean areas, if for no other reasons than to keep faith with our representations to the Congress and the nation, and to enable us to exercise the proprietary rights which we had so effectively and vigorously asserted.

California law, as it existed prior to Sept. 7, 1955, did not authorize the issuance by the State Lands Commission of oil and gas leases embracing the state-owned tide and submerged lands except in the limited instances where such lands were being drained or threatened with drainage by means of wells upon adjacent lands. Because there are only a few isolated instances in which such drainage or the threat thereof exists, most submerged land belt lying offshore the coast of California could not be opened to exploratory drilling until this provision of the law was repealed.
Fracture Width Logging While Drilling and Drilling Mud/Loss-Circulation-Material Selection Guidelines in Naturally Fractured Reservoirs
Authors: Liétard Olivier , Unwin Tessa , Guillo D. J. , Hodder M. H.
Published: December 2007

In this article we discuss drilling mud losses in naturally fractured reservoirs with fracture permeability larger than 50 odd md and much larger than the matrix permeability.

Type curves are provided that describe mud loss volume vs. time and allow the determination of the hydraulic width of natural fractures through the usual type curve matching technique of log/log plots.

Real time logging while drilling of natural fracture width permits the proper selection of loss-circulation material (LCM) with respect to particle size distribution. Efficient (rapid) mud loss control is made possible, increasing the chances of minimizing fracture damage by the drilling mud, the cuttings and the LCMs themselves.

The total mud losses experienced when drilling a long horizontal section are shown to agree with reservoir properties (derived by well testing) in particularly well-documented examples of the central North Sea.

The equations provided can therefore be utilized as well by reservoir engineers to properly evaluate the contribution of natural fractures to the permeability and skin of any well, whether these fractures are clear or are invaded by drilling mud.
Formation-Damaging Characteristics of Mixed Metal Hydroxide Drill-In Fluids and a Comparison With Polymer-Base Fluids
Authors: Fraser L. J. , Reid P. I. , Williamson L. D. , Enriquez F. P.
Published: December 2007

Horizontal wells are commonly completed without casing and the fluids used to drill said sections can have a significant effect on the production outcome. Mixed metal hydroxide (MMH)/bentonite-based fluids are compared to two commonly used reservoir drill-in fluids (DIFs) with respect to filter-cake characteristics and regain in permeability. The MMH fluids are found to produce filter cakes with unique features which result in efficient backflow without need for chemical treatment. Return permeability results which equal or exceed those for more commonly used DIFs raise questions over the conventional view that bentonite-containing DIFs are harmful to reservoirs.
Wettability Change Related to Adsorption of Organic Acids on Calcite: Experimental and Ab Initio Computational Studies
Authors: Legens Christelle , Toulhoat Hervé , Cuiec Louis , Villieras Frédéric , Palermo Thierry
Published: December 2007

We have investigated the interactions between organic acids and a calcite powder by adsorption from an organic phase (benzoic acid and lauric acid in toluene) and from an aqueous phase (benzoic acid and lauric sodium salt).

In addition to the experimental study, ab initio quantum chemistry calculations were performed for cluster models, simulating the interactions of molecules with calcite surface sites.

At the toluene/calcite interface, acids chemisorb on surface calcium ions, replacing surface hydroxyls resulting from the previous surface hydration by water. This surface saponification phenomenon was predicted by ab initio calculations and confirmed by spectroscopic techniques. The adsorbed acids conferred a hydro-phobic character to calcite, with the higher contact angles in water for the longest alkyl chains in the organic acid.

At the water/calcite interface, organic acids do not displace water.

Our results support the possible existence of mixed wettability patterns, related to spatial distribution of pore sizes, in the specific case of organic acids with calcite.
A Buckling Criterion for Constant-Curvature Wellbores
Authors: Mitchell Robert F.
Published: December 2007

This paper examines the effect of wellbore curvature on the buckling stability of casing. A large-displacement/small-strain analysis was used to obtain a general stability result, including all curvature effects. Two types of analysis are provided for comparison and contrast. The first analysis is an equilibrium analysis, which provides not only the stability criterion desired, but additional information, such as the contact force between the casing and the wellbore. The second analysis is an energy balance. This analysis was developed to provide a comparison with other stability results, some of which differ from the calculations presented here. Previous papers investigating this problem have produced conflicting results. This paper resolves the conflict.
Identification of Geological Shapes in Reservoir Engineering By History Matching Production Data
Authors: Rahon Daniel , Edoa Paul Francis , Masmoudi Mohamed
Published: December 2007

This paper discusses a method which helps identify the geometry of geological features in an oil reservoir by history matching of production data. Following an initial study on single-phase flow and applied to well tests (Rahon, D., Edoa, P. F., and Masmoudi, M.: "Inversion of Geological Shapes in Reservoir Engineering Using Well Tests and History Matching of Production Data," paper SPE 38656 presented at the 1997 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 5-8 October.), the research presented here was conducted in a multiphase flow context.

This method provides information on the limits of a reservoir being explored, the position and size of faults, and the thickness and dimensions of channels.

The approach consists in matching numerical flow simulation results with production measurements. This is achieved by modifying the geometry of the geological model. The identification of geometric parameters is based on the solution of an inverse problem and boils down to minimizing an objective function integrating the production data.

The minimization algorithm is rendered very efficient by calculating the gradients of the objective function with respect to perturbations of these geometric parameters. This leads to a better characterization of the shape, the dimension, and the position of sedimentary bodies.

Several examples are presented in this paper, in particular, an application of the method in a two-phase water/oil case.
Influence of Thermal History on the Waxy Structure of Statically Cooled Waxy Crude Oil
Authors: Chang Cheng , Boger D. V. , Nguyen Q. D.
Published: December 2007

The effect of the thermal history on the waxy structure of two statically cooled waxy crude oils is examined using a controlled stress rheometer for rheological measurements and a microscope to observe microstructure of wax crystals. A three-yield-stress model is used to describe the yielding of the samples at low temperatures. The elastic-limit, static, and dynamic yield stresses as a result of different static cooling processes were determined from controlled stress and oscillatory rheological measurements. The types of histories examined include the temperature, cooling rate (0.5 to 4°C/min), and isothermal holding time before testing (up to 15 hours). In addition, the reversibility over time of the waxy structure after yielding was investigated. The results from both yield stress measurements and microscopic observations show that the waxy structure strongly depends on both the temperature and the cooling rate. The isothermal holding time both before and after yielding was found to have no observable influence on the structure over the time period studied in these experiments.
Estimating the Pressure-Transient Response for a Horizontal or a Hydraulically Fractured Well at an Arbitrary Orientation in an Anisotropic Reservoir
Authors: Spivey J. P. , John Lee W.
Published: December 2007

This article presents a method for finding the equivalent isotropic system for a horizontal well or a hydraulically fractured well at an arbitrary azimuth in an anisotropic reservoir. The equivalent isotropic system can then be used to calculate the pressure response of the original system.

The horizontal well solution is compared with previous solutions reported in the literature. The general hydraulically fractured well case has not, to our knowledge, been presented before.

This study confirms the observation by Yildiz and Ozkan1 that small deviations (up to 20°) from the optimal azimuth for a horizontal well do not have a major effect on the pressure response. Because this solution is obtained by finding an equivalent isotropic system, this study also confirms the observation by Earlougher2 that an anisotropic system cannot be identified from a single-well test.
Determination of the Orientation of a Vertical Fracture by Interference Tests
Authors: Uraiet A. , Raghavan R. , Thomas G.W.
Published: December 2007

An analytic solution for the pressure distribution around a fractured well in a homogeneous, infinite reservoir is presented in terms of tabulated functions. This solution can be used to determine fracture orientation from interference tests.

Introduction

The advent of costly tertiary recovery programs has resulted in the need to determine flow patterns created by fractures intersecting wellbores. This requires a knowledge of the compass orientation and length of fractures. Several papers have discussed determination of fracture length by pressure analysis. However, methods for determining the compass orientation using pressure data have not received much attention. This paper pressure data have not received much attention. This paper discusses a method for determining the compass orientation using pressure data obtained at shut-in observation wells due to pressure data obtained at shut-in observation wells due to production or injection at the fractured well. production or injection at the fractured well. In 1960 Elkins and Skov reported a method for determining the orientation of natural fractures. They assumed the system of natural fractures to behave like an anisotropic system and used the classical line-source solution to analyze, pressure behavior. More recently, Pierce et al. demonstrated the use of pulse testing for calculating fracture length and orientation. Other studies on the determination of fracture orientation include (1) use of acoustic signals; (2) measurement of pressure response at observation wells during fracture initiation and propagation; and (3) use of inflation impression packers and television cameras.Even though the problem has been recognized for quite some time, no general method exists for determining pressure distribution in the area drained by a vertically fractured well. The objective of this paper is to present an analytic expression, in terms of simple tabulated functions, for the pressure distribution in a uniform, homogeneous, infinite reservoir drained by a vertically fractured well. This solution may be used to analyze pressure data in adjacent observation wells to determine fracture orientation in a manner analogous to standard interference tests. It also may be used to analyze test data obtained by pulsing a vertically fractured well. pulsing a vertically fractured well. Theory

The mathematical model considered in this study is identical to the uniform-flux fracture examined by Gringarten et al. We assume that a single vertical fracture intersects a wellbore located in an infinite, homogeneous, porous medium (Fig. 1). The surface production rate is assumed to be constant and all the production is obtained by means of the fracture. Fluid enters production is obtained by means of the fracture. Fluid enters the fracture at the same rate per unit area of the fracture (uniform-flux fracture).

JPT

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