bluuebunny/crossref_metadata_2025 huggingface dataset:
Reaction Rate and Fluid Loss: The Keys to Wormhole Initiation and Propagation in Carbonate Acidizing
Authors: Huang Tianping , Hill A. D. , Schechter R. S.
Published: December 2007

The efficiency of the matrix acidizing process in carbonates depends strongly on the wormholing phenomenon—if wormholes are formed, the effects of near-wellbore damage can be overcome with relatively small volumes of acid. Numerous previous studies have shown that wormhole patterns can be placed in these general categories: compact dissolution in which most of the acid is spent near the rock face; the wormholing pattern; and uniform dissolution in which many pores are enlarged, as typically occurs in sandstone acidizing. We have developed a theory of the wormholing process, which predicts when the wormholing pattern is most efficiently created as a function of the acid flux and other treatment variables.

By testing this theory with several independent sets of laboratory data, we can now demonstrate the important roles that surface reaction rate and fluid loss play in the wormholing process. This theory accurately predicts the optimal flux (that which leads to dominant wormholes with a minimum of branching, and hence, a minimum acid volume) for experiments with HCl in limestone and dolomite at several temperatures and with acetic acid in limestone. The surface reaction rate differs by several orders of magnitude in these experiments and is the only process variable that differs greatly among them. Paradoxically, though wormholes are formed because the overall reaction rate is controlled by mass transfer in the wormholes, diffusion rates play only a minor role in the wormholing process.

Fluid loss through the walls of the wormholes ultimately limits the distance to which wormholes can propagate. Because of this effect, laboratory linear corefloods will give optimistic predictions of wormhole penetration distances. We developed a cylindrical flow model to represent the flow field around a wormhole propagating from a wellbore which illustrates how to translate laboratory results to field conditions.

We have used these theories to predict optimal acid formulations and injection rates for field conditions. In general, the lower the reaction rate (such as at low temperatures in dolomites or with weak acids in limestone), the lower the injection rate required, making it easier to propagate dominant wormholes under matrix treating conditions in the field.
Effect of Brine Salinity and Crude-Oil Properties on Oil Recovery and Residual Saturations
Authors: Sharma M. M. , Filoco P. R.
Published: December 2007

Centrifuge experiments were conducted on Berea cores to measure the drainage and imbibition relative permeabilities in two-and three-phase systems. Three crude oils, Prudhoe Bay and Shell Mars A-1 and A-20 crude were used in our tests. No effect on oil recovery was obtained in the drainage experiments when the crude oil was displaced by air at connate water. However, in the imbibition experiments the oil recovery increased significantly with the salinity of the connate brine. The salinity of the displacing brine had no significant influence on the oil recovery. The relative permeability curves obtained during drainage were also found to be insensitive to the salinity of the brine. However, the imbibition relative permeability curves show strong salinity dependence. A comparison of the two crude oils and a nonpolar mineral oil indicates that the more water-wetting Mars crude oil shows a higher oil relative permeability at the same bond number compared to the mixed-wetting Prudhoe Bay crude oil. The salinity dependence of the residual saturations and the relative permeabilities clearly indicate that the change in wetting properties of the rocks surfaces from water-wet to mixed-wet during the drainage process is an important factor controlling the imbibition relative permeability curves. This suggests that the performance of waterfloods will be strongly affected by the composition of the crude oil and its ability to wet the rock surfaces, the salinity of the connate brine in the reservoir, and the height above the oil/water contact.
Litho-Facies and Permeability Prediction From Electrical Logs Using Fuzzy Logic
Authors: Cuddy S. J.
Published: December 2007

Several areas of the geosciences have benefitted from the application of the new mathematics of "fuzzy logic."1,2 The oil industry now routinely uses new interpretation techniques, based on fuzzy logic, to predict permeability and litho-facies in uncored wells. Litho-facies and permeability prediction have presented a challenge to formation evaluation due to the lack of tools that measure them directly. The method described can be used as a simple tool for confirming known correlations or as a powerful predictor in uncored wells.

Fuzzy logic is simply an application of recognized statistical techniques. Whereas conventional techniques deal with absolutes, the new methods carry the inherent error term through the calculation rather than ignoring or minimizing it. This retains the information associated with the error and gives surprisingly better results.

One clear application is to litho-facies determination. Litho-facies typing is used in well correlation and is important for building a three-dimensional model of an oil or gas field. The technique makes no assumptions and retains the possibility that a particular litho-facies type can give any well log reading although some are more likely than others. This error or fuzziness has been measured and used to improve the litho-facies prediction in several North Sea fields. In one study, descriptions from 10 cored wells were used to derive litho-facies descriptions in 30 uncored wells. This technique gave near-perfect differentiation between aeolian, fluvial, and sabkha rock types. In addition, it went some way towards differentiating between sandy, mixed, and muddy sabkhas. Using the fuzzy logic technique gives much better predictions than more complicated methods such as neural networks or cluster analysis.

A second application is permeability calculation. Knowledge of permeability is important in determining the well completion strategy and the resulting productivity. The problem with permeability prediction is derived from the fact that permeability is related more to the aperture of pore throats rather than pore size, which logging tools find difficult to measure. Determining permeability from well logs is further complicated by the problem of scale, well logs having a vertical resolution of, typically, 2 ft compared to the 2 in. of core plugs. The new techniques quantify these errors and use them, together with the measurement, to improve the prediction. This new approach has been used in several fields to obtain better estimates of permeability compared to conventional techniques. In addition, the method uses basic log data sets such as gamma ray and porosity rather than depending on new logging technology.
Unified Mechanistic Model for Steady-State Two-Phase Flow: Horizontal to Vertical Upward Flow
Authors: Gomez L. E. , Shoham Ovadia , Schmidt Zelimir , Chokshi R. N. , Northug Tor
Published: December 2007

A unified steady-state two-phase flow mechanistic model for the prediction of flow pattern, liquid holdup and pressure drop is presented that is applicable to the range of inclination angles from horizontal (0°) to upward vertical flow (90°). The model is based on two-phase flow physical phenomena, incorporating recent developments in this area. It consists of a unified flow pattern prediction model and unified individual models for stratified, slug, bubble, annular and dispersed bubble flow. The model can be applied to vertical, directional and horizontal wells, and horizontal-near horizontal pipelines. The proposed model implements new criteria for eliminating discontinuity problems, providing smooth transitions between the different flow patterns.

The new model has been initially validated against existing, various, elaborated, laboratory and field databases. Following the validation, the model is tested against a new set of field data, from the North Sea and Prudhoe Bay, Alaska, which includes 86 cases. The proposed model is also compared with six commonly used models and correlations. The model showed outstanding performance for the pressure drop prediction, with a −1.3% average error, a 5.5% absolute average error and 6.2 standard deviation. The proposed model provides an accurate two-phase flow mechanistic model for research and design for the industry.
Horizontal-Wellbore Stability and Sand Production in Weakly Consolidated Sandstones
Authors: van den Hoek P. J. , Kooijman A. P. , de Bree P. , Kenter C. J. , Zheng Z. , Khodaverdian M.
Published: December 2007

Long-term stability of horizontal wellbore completions with uncemented liners in weakly consolidated to unconsolidated sandstone formations (e.g., the Gulf of Mexico and Nigeria) remains an area of concern. In this paper we present the results of dedicated polyaxial cell laboratory experiments that address this issue. In addition, the influence of rock failure in the near-wellbore region on well productivity was studied.

Large blocks of a weak artificial sandstone were prepared. A hole was drilled in these blocks, and production conditions at various values of in-situ stress, drawdown and water cut, both in the absence and presence of a liner, were simulated. During testing, the hole was kept at a horizontal position in order to realistically simulate the influence of gravity forces on the movement of sand debris. The process of hole failure and re-stabilization was continuously monitored by an endoscope coupled to a video camera.

The experimental results show that in the presence of a slotted liner, and in the absence of a water cut, rock failure leads to gradual annulus fillup with loose sand, eventually resulting in a stable configuration in which only a small fraction of the far-field stresses is transferred to the liner. These results are further supported by elasto-plastic calculations. Rock failure around the liner is shown to have only a minor effect on productivity. This result implies that rock failure around uncemented liner completions will generally not be noticed at the wellhead.

The introduction of a small (<5%) water cut resulted in massive sand production and subsequent liner collapse. This can be explained by the fact that a water cut destroys capillary cohesion, thereby destabilizing sand arches over the slots.
A New Concept of Sand Production Prediction: Theory and Laboratory Experiments
Authors: van den Hoek P. J. , Hertogh G. M. M. , Kooijman A. P. , de Bree Ph. , Kenter C. J. , Papamichos E.
Published: December 2007

Conventional theories of sand production prediction distinguish between compressive (shear) cavity (perforation, borehole) failure, induced by a combination of in-situ stress and drawdown, and tensile cavity failure, induced by the near-cavity pore pressure gradient. In this paper we show, using a global criterion for strain localization around the cavity (i.e., cavity failure), that in most cases the preference for either compressive or tensile cavity failure only depends on the cavity size and on the constitutive properties of the rock, and not on effective near-cavity stress or the pore pressure gradient. It is shown that "large" cavities (e.g., boreholes) always fail in compression rather than in tension failure. Only for sufficiently small cavities (e.g., perforations) in weak, moist sandstones, is compressive failure supressed and tensile failure possible. The above results deviate significantly from previous sand production prediction concepts. They are further supported by laboratory sand production experiments with large cavities, in which sand failure was only observed for near-cavity effective stresses above a certain threshold, independent of applied drawdown (i.e., flow rate). The experiments exhibited no correlation between the (non) occurrence of sand production and drawdown.

From these results, it may be concluded that the primary role of fluid flow in sand production is the transport of loose sand (debris) resulting from compressive failure, rather than failure of the intact sandstone itself.
Innovative Real-Time Well-Monitoring Systems (ESP Applications)
Authors: Moffatt Terry , Craig Doug
Published: December 2007

The increasing need for downhole data related to modern production practices has resulted in the growing use of permanent well-monitoring systems (Fig. 1) for both offshore and land-based applications. The development of these technologies has furthered the ability of production and reservoir engineers to make more proactive decisions based on downhole-measured conditions.

This paper takes a cursory look at an innovative technology that has been used in both low- and high-temperature applications. The focus of the paper is on the applications and case studies in which the instrumentation has been employed. Information gathered, education gained, and value of the data is discussed for applications involving electrical submersible pumping (ESP) systems.
Permeability Modification With Sulfomethylated Resorcinol-Formaldehyde Gel System
Authors: Zhuang Y. , Pandey S. N. , McCool C. S. , Willhite G. P.
Published: December 2007

The effect of various parameters on the gelation of the resorcinol-formaldehyde (RF) system and a newly developed sulfomethylated resorcinol-formaldehyde (SMRF) system was investigated. The SMRF system was more tolerant of salinity, divalent ion content and pH than the RF system. The SMRF system was tested in laboratory core floods conducted at 41°C (106°F) using Berea sandstone cores, Baker dolomite cores and reservoir rock from the Lansing-Kansas City formation.

SMRF forms strong and stable gels at temperatures between 25 and 52°C (77 and 126°F) and in the pH range between 5 and 8.0. Gel times are a function of pH, salinity, concentration of the chemical constituents and temperature, and can be controlled by appropriate adjustment of these parameters. Laboratory data describing the characteristics of the SMRF system in beaker tests are presented.

The SMRF gel system has a viscosity close to water when the reactants are mixed and is easily injected into porous rock. In core tests, the gel system was injected into short cores and allowed to gel in situ. Permeability to brine after in-situ gelation was determined for each core as well as permeability after several pore volumes of brine injection. The SMRF gel system reduced the permeabilities of Berea and Baker dolomite cores by factors on the order of 10,000. The Lansing-Kansas City reservoir rock was plugged by the gel system.

The SMRF gel system is one of a few gel systems that will form a gel in situ in the presence of the strong buffering that occurs when brine is injected into carbonate rock. The SMRF system has potential for treatments of carbonate matrix rock such as that found in the Lansing-Kansas City formations of central Kansas as well as the low-permeability carbonates found in the San Andres formations in west Texas.
Theoretical and Experimental Studies of Sandstone Acidizing
Authors: Hill A. D. , Lindsay D. M. , Silberberg I. H. , Schechter R. S.
Published: December 2007

The matrix acidization of sandstone by a hydrochloric/hydrofluoric acid mixture is described through use of a capillary model. The model was solved first in linear coordinates so that it could be compared with the results of coreflood experiments performed on Berea sandstone. The model predictions showed reasonable agreement with the experimental data and yielded specific information about the reaction characteristics of the sand-stone/HCl/HF system.

The acidization model then was applied in radial coordinates to generate design curves for a matrix acidization treatment. While these curves strictly apply only to those sandstones having similar mineral compositions, the approach is general. It is based on matching the location of the HF reaction front to the depth of a damaged zone. This method introduces the concept of an optimum injection rate and, in this regard, differs from other design methods reported in the literature.
Adaptation of Friction Factors to the Flow of Fluids Through Consolidated Formations
Authors: Stutzman L.F. , Thodos George
Published: December 2007

The friction factor plot presented by Cornell and Katz and developed for the flow of fluids through consolidated formations has been directly adapted for handling fluid flow problems involving both linear and radial flow. In this adaptation the friction factor plot is used directly for the solution of problems and thereby eliminates the use of conventional equations which are specific to laminar (Darcy) or turbulent flow. This approach overcomes the disadvantages inherent in the use of these conventional equations. It eliminates the necessity of checking the type of flow occurring in order to identify the specific equation which must be used. In radial flow problems, because of the increasing mass velocity of the fluids as they approach the wellbore, the type of flow may no longer remain laminar. Consequently, it is necessary to use more than one equation in a problem and to identify the range over which each equation should be applied. Finally, in practice it has been found that much of the flow of gases through consolidated media occurs in a range that is neither laminar or turbulent. For this transitional region, no convenient equations are available. The method and presented friction factor plot are applicable to both liquids and gases.

Introduction

The flow of fluids through unconsolidated media in packed beds has been treated extensively by a number of investigators. Most of these studies present friction factors as a function of modified Reynolds number similar to those developed for conventional fluid flow through pipes. These friction factor plots are presented for linear flow; however, Elenbaas and Katz have extended these concepts to apply to radial flow. All of these studies on unconsolidated materials require a knowledge of packing properties such as sphericity, porosity, and particle diameter. Sphericity and particle diameter cannot be defined at the present time for consolidated formations such as those commonly found in gas or oil reservoirs. As a result many investigators have not utilized friction factors and Reynolds number in the study of fluid flow through consolidated media.
Journey From Well Logs/Cores to Integrated Geological and Petrophysical Properties Simulation: A Methodology and Application
Authors: Bahar A. , Kelkar M.
Published: December 2007

Reservoir studies performed in the industry are moving towards an integrated approach. Most data available for this purpose are mainly from well cores and/or well logs. The translation of these data into petrophysical properties, i.e., porosity and permeability, at interwell locations that are consistent with the underlying geological description is a critical process. This paper presents a methodology that can be used to achieve this goal. The method has been applied at several field applications where full reservoir characterization study is conducted.

The framework developed starts with a geological interpretation, i.e., facies and petrophysical properties, at well locations. A new technique for evaluating horizontal spatial relationships is provided. The technique uses the average properties of the vertical data to infer the low-frequency characteristics of the horizontal data. Additionally, a correction in calculating the indicator variogram, that is used to capture the facies' spatial relationship, is provided.

A new co-simulation technique to generate petrophysical properties consistent with the underlying geological description is also developed. The technique uses conditional simulation tools of geostatistical methodology and has been applied successfully using field data (sandstone and carbonate fields). The simulated geological descriptions match well the geologists' interpretation. All of these techniques are combined into a single user-friendly computer program that works on a personal computer platform.
Interference Testing in Reservoirs With Conductive Faults or Fractures
Authors: Abbaszadeh M. , Asakawa K. , Cinco-Ley H. , Arihara N.
Published: December 2007

This paper addresses interference testing in reservoirs with conductive faults allowing fluid flow along and across the fault plane. An altered skin region around fault thrusts is also included. It is found that the classical line-source solution does not apply. When active and observation wells are located across a fault, the interference behavior resembles that of a hydraulically fractured well with bilinear flow characteristics. However, different flow regimes are developed on the pressure derivative when the well pairs are situated at the same side: initially, the basic line-source behavior; then, constant pressure effect from the fault represented by a negative unit-slope line; and, finally, bilinear flow. Interference type curves for various regions in the reservoir are developed and practical guidelines are provided for interpretation of these tests. Field data from an interference test in a faulted carbonate reservoir are analyzed and fault parameters are estimated.
A New Approach for Accurate Prediction of Loading in Gas Wells Under Different Flowina Conditions
Authors: Nosseir M. A. , Darwich T. A. , Sayyouh M. H. , Sallaly M. El
Published: December 2007

Several authors have introduced various mathematical equations to calculate the critical flow rate necessary to keep gas wells unloaded. The most widely used equation is that of Turner et al.1 However, Turner's equation required empirical adjustment with different ranges of data which made the application rather questionable. In this paper we present a new approach for calculating the critical flow rate necessary to keep gas wells unloaded. This approach still adopts Turner's basic concepts, but considers different flow conditions that result in different flow regimes. Hence it explains the previous discrepancies of Turner's equation (the droplet model) with different data ranges, and presents a new set of equations that eliminates the need for empirical adjustment and better matches actual data records.
Long-Term Hydraulic-Fracture Conductivities Under Extreme Conditions
Authors: Cikeš Marin
Published: December 2007

Proppants for hydraulic fracturing are subjected to very severe conditions of stress, temperature, and chemical environment while they are expected to maintain their structural integrity for a period of many years. The performance of these proppants over time at simulated in-situ conditions has been a topic of laboratory investigation for several years, but in many cases the real conditions exceed the capabilities of the laboratory apparatus. To determine the proppant behavior under real reservoir conditions, production history and pressure buildup tests of four fractured wells have been analyzed. The reservoir conditions of these wells are so severe, that it was almost impossible to simulate them in the laboratory. The formation temperature is 179 to 195°C [354 to 383°F], while the reservoir pressure varies between 44.5 and 50.0 MPa [6,453 to 7,250 psi]. The producing fluid is large gravity sour gas, while the producing water is practically deionized. The proppants are mainly high-strength zirconium oxide and sintered bauxite that injected amount varies between 164 and 628 tons [3.6E + 05 to 1.38E + 06 lbm]. During the production time of six to eight years, the effective closure stress reached the values in the range of 32 to 51 MPa [4,640 to 7,395 psi].
More Than 12 Years' Experience With a Successful Conformance-Control Polymer-Gel Technology
Authors: Sydansk R. D. , Southwell G. P.
Published: December 2007

In this paper, we discuss and describe our extensive experience with the widely applied and quite successful Cr(III)-carboxylate/ acrylamide-polymer (CC/AP) gel technology for use in oilfield conformance-control, sweep-improvement, and water and gas shutoff treatments. Chromic triacetate is the often preferred chemical crosslinking agent used in conjunction with this polymer-gel technology. The CC/AP gel technology is characterized as having a robust gel chemistry and as being highly insensitive to petroleum reservoir environments and interferences. This gel technology, as of May 1998, has been employed in over 1,400 conformance-control treatments worldwide. Highlights of illustrative field applications and results involving the CC/AP conformance-control gel technology are presented. An overview of what a decade plus of experience in applying the CC/AP gel technology has taught us is discussed. This includes discussion of classifying and distinguishing conformance problems and treatments, attributes of good candidate wells and well patterns for gel conformance-control treatments, requirements that must be met in candidate wells and well patterns in order to achieve success, gel treatment elements that must be successfully implemented to achieve success, guidelines as to where polymer-gel conformance treatments are most successfully applied, risks and pitfalls of gel conformance treatments, and quality control issues.
Simulation With a Full-Tensor Coefficient Velocity Field Recovered From a Diagonal-Tensor Solution
Authors: Edwards M. G.
Published: December 2007

Commercial simulators generally assume that the pressure equation always has a diagonal-tensor permeability field. However, cases that involve the use of non-Cartesian grids, crossbedding, or upscaling (or any combination thereof) will give rise to a full-tensor coefficient velocity field. Discretization of a full tensor increases the scheme stencil, simulation cost, and complexity of implementation. The focus of this paper is on the development of fully implicit finite-volume schemes that can allow full-tensor fluxes while retaining standard-matrix inversion.
Estimating Relative Permeability From Production Data: A Streamline Approach
Authors: Kulkarni K. N. , Datta-Gupta Akhil
Published: December 2007

We present a streamline-based approach for estimating relative permeabilities from production data. The streamline approach offers two principal advantages. First, we can analytically compute the sensitivity of the production response with respect to relative permeability parameters. The approach is extremely fast and requires a single streamline simulation run. Second, we can exploit the analogy between streamlines and seismic ray tracing to develop a formalism for efficient inversion of production data. For relative permeability representations we have used the commonly used power functions and also a more flexible representation through the use of B-splines. The relative advantages of these representations are examined through inversions of water-cut data from a nine-spot pattern. Finally, we address the underlying challenges associated with the simultaneous estimation of absolute and relative permeabilities from production data. We systematically investigate the nonuniqueness associated with the inverse problem and quantitatively evaluate the role of additional data such as pressure response in addition to water-cut history at the wells.
The Application of an Electronic Computer to the Calculation of the Recovery of Natural Gasoline by Refrigeration
Authors: Roberts S.M.
Published: December 2007

A study of the recovery of natural gasoline from natural gas by refrigeration was made with the aid of an IBM 650 computer. A form of the familiar "flash" equation, chosen to minimize calculation time, was employed to determine the natural gasoline recovery. An eight-component system can be solved in about 30 seconds for each pressure and temperature combination.

The ranges of the variables studied aregasoline content (isobutane and heavier) of the wet gas, 0.891 to 3.293 gal/Mcf,pressure, 50 psia to 1,000 psia, andtemperature, −20 degrees F to +40 degrees F.

For the gases considered the gasoline content of the discharge gas decreases more or less linearly with pressure to about 300 psia and then levels off. For all but the leanest gas, the gasoline content of the discharge gas can be reduced to 0.45 gal/Mcf at 400 psia and 0 degrees F. Under certain conditions of pressure and temperature the gasoline content can be reduced to as low as 0.25 gal/Mcf. In this case a large penalty is paid in the excessive recovery of propane and lighter in the liquid, The extraction efficiency is often a more satisfactory measure of the utility of the process than is the gasoline content of the discharge gas. The extraction efficiency increases more or less linearly to about 300 psia and then levels out beyond 600 psia. For all but the leanest wet-gas the isobutane and heavier extraction efficiency exceed 70 per cent at 400 psia and 0 degrees F. Under certain conditions the efficiency may exceed 90 per cent. At a given pressure and temperature, the richer the wet gas, the higher is the extraction efficiency.

Introduction

The recovery of natural gasoline from natural gas by refrigeration is a special field processing method. A study was made to establish the area of application of the method. The first step was to determine the ultimate physical recovery of liquid product, and the second step, to determine the economic recovery of liquid product. This paper will deal only with the first step. It describes in some detail the program for solving the flash equation with the aid of the IBM 650 computer and reports the calculated results. A somewhat similar study has been reported by Stamm, McCarty, Allen and Moore, but for a more limited range of wet-gas compositions and operating conditions.
The Impact of Compression Forces on Casing-String Designs and Connectors
Authors: Jellison M. J. , Brock J. N.
Published: December 2007

The effect of downhole axial compression forces on casing string designs and connectors is a major concern to engineers designing high-temperature, high-pressure, extended reach, and horizontal wells. Widespread concern regarding the significance of compression loads on casing string design is relatively recent. For decades engineers were either not aware that high-compression loads may occur or were not concerned about the effect of compression on the casing.

This paper discusses the sources of axial compression forces in straight and directional wells. Methods to analyze casing subjected to compression and bending loading are presented including the effect of compression and bending on the von Mises equivalent stress state of the pipe.

Connector selection for casing applications where high axial compression loads are anticipated is critical. Compression ratings for API casing connectors have never been addressed in API standards. The paper offers methods to evaluate API connectors for applications with significant compression loading. Compression ratings for premium casing connectors are generally available, but the justification for these ratings varies substantially from one manufacturer to another and the basis for the compression ratings may not be well documented. The paper discusses compression rating methods for various premium connector configurations including threaded and coupled, flush and near flush. Desirable and undesirable premium connector features that relate to compression capacity are reviewed. Results from compression testing of premium connectors are also presented.

The paper benefits engineers involved in the design of casing strings for applications with high compression and bending loading.
Case History of Complex-Fracture Behavior in the Hanoi Trough, Vietnam
Authors: Cipolla C. L. , Mayerhofer M. , Wilson B. L.
Published: December 2007

In this paper we present a detailed case history of complex fracture behavior in exploratory wells in the Hanoi Trough, Vietnam. The target formations are stacked fluvial channel deposits that occur at depths of 10,000 to 12,000 ft. The initial three wells were drilled from the same pad, with bottomhole locations about 3,000 to 5,000 ft apart and a probable fault between the No. 1 and No. 3 well. The gas reservoirs encountered were slightly overpressured and varied significantly in quality, with permeability ranging from 0.01 to 1 md. The first three wells were fracture stimulated in an attempt to improve deliverability. However, only one of the three treatments was successful due to complex fracture behavior. A comprehensive data set consisting of core analysis, rock mechanical tests, pre- and post-fracture logs, geochemical analyses, pre- and post-fracture well tests, and detailed fracture modeling was compiled to understand fracture performance in this complex environment. Without such a complete data set, identifying the cause of the treatment failures would probably not have been possible.
Particulate Invasion From Drilling Fluids
Authors: Bailey Louise , Boek E. S. , Jacques S. D. M. , Boassen Tony , Selle O. M. , Argillier J. -F. , Longeron D. G.
Published: December 2007

We investigate the invasion of solids and their mobility during cleanup. We study the effect of weighting agent particle size on rock substrates of varying permeabilities. We find permeability damage increases but flow initiation pressures decrease with increasing substrate permeability.

We obtain quantitative profiles of solids invasion by scanning electron microscopy/x-ray mapping and synchrotron energy-dispersive x-ray diffraction tomography. We compare these profiles to core sectioning data. We find invasion profiles drop steeply but fines are observed deep within the core. We examine the effect of backflooding on the invasion profile. Near-surface damage is reduced but deeply invaded fines are unaffected by backflow.

We develop a deep bed filtration model for solids invasion and consequent permeability reduction. This model is compared to the profiles obtained in the invasion experiments. We find that we can fit the experimental invasion profile for monomodal particles using a single trapping coefficient. Backflow is modeled by reversing the flow rate. We postulate a phenomenological rate of erosion to untrap particles in line with experimental observations (30%). When erosion is included in the model, a peak in the backflow pressure is found. This peak may be correlated with the experimentally observed flow initiation pressure.
Calculation Methods for Linear and Radial Steam Flow in Oil Reservoirs
Authors: van Lookeren J.
Published: December 2007

The flow of oil and water in a reservoir as a result of steam injection is related to the shape of the growing steam zone. Analytical formulas describing the approximate shape of this zone have been derived both for linear flow in horizontal and dipping formations and for radial flow around injection wells in a horizontal formation.

The theory is based on segregated-flow principles such as those previously used by Dupuit,1 Dietz,2 and others. The formulas take into account gravity overlay of steam zones and have been checked against results of scaled laboratory experiments, steam-injection projects in the field, and calculations with a numerical reservoir simulator. From the good agreement with the new calculation method it would seem that the shape of a steam zone is controlled mainly by one group of parameters including steam-injection rate, pressure, and effective formation permeability to steam.

The equations can be used to analyze and explain field observations, such as the position of steam/liquid contacts in injection wells, estimates of effective permeability to steam in steam zones, and steam-zone thickness as noticed in observation wells. This paper shows, for example, how a cumulative oil/steam ratio for oil displaced from a steam zone depends on steam-zone pressure, injection rate, and time.

With increasing oil viscosity, more bypassing of oil by steam owing to viscous forces will occur, leading to more overlay of steam zones and eventually to narrow tonguing in a lateral direction.

The calculation methods provide an evaluation tool for steamdrive and steam-soak processes to reservoir engineers engaged in field operations, project design, and research.
An Empirical Model for Three-Phase Relative Permeability
Authors: Blunt M. J.
Published: December 2007

We present an empirical model for three-phase relative permeability. We allow for changes in hydrocarbon composition, different saturation paths, and the trapping of oil, water, and gas. The model is based on saturation-weighted interpolation between the two-phase relative permeabilities. By writing the relative permeabilities as unique functions of a flowing saturation, the model predicts the behavior for any sequence of saturation changes and accounts for trapping. Layer drainage allows the oil relative permeability to be extrapolated to low saturation. The formulation for water-wet media, including layer drainage and trapping, is tested against experimental three-phase data.
Gravitational Potential Variations of the Sun and Moon for Estimation of Reservoir Compressibility
Authors: Chang Eric , Firoozabadi Abbas
Published: December 2007

Total compressibility in a fractured reservoir is estimated using the pressure response due to gravitational potential variations. Both the lunar and the solar gravitational potentials are fully accounted for by inclusion of longer-period components. The semidiurnal and diurnal pressure data show substantial long-term variations. The gravitational potential also contains the same variation trend: the ratio between the potential and pressure has a fairly uniform value over successive cycles. The computed total compressibility is also fairly constant and independent of the cycle.
Conditioning 3D Stochastic Channels to Pressure Data
Authors: Bi Zhuoxin , Oliver D. S. , Reynolds A. C.
Published: December 2007

This work discusses the development and implementation of a procedure to condition a stochastic channel to well-test pressure data and well observations of the channel thickness and the depth of the top of the channel. The stochastic channel is defined by a set of geometric random variables (referred to as geometric model parameters) that describe the location, size, and shape. Channel and nonchannel permeability and porosity are treated as random variables. These four random variables plus the geometric parameters comprise the complete set of model parameters. Multiple conditional realizations of the geometric parameters and rock properties are generated to evaluate the uncertainty in model parameters and the reduction in uncertainty obtained by conditioning to well-test pressure data.
Hydrate Control During Deepwater Drilling: Overview and New Drilling-Fluids Formulations
Authors: Ebeltoft Hege , Majeed Yousif , Sœrgärd Eirik
Published: December 2007

Gas-hydrate formation during deepwater offshore drilling is a well-recognized operational hazard. Plugging the blowout preventer (BOP) stack, choke, and kill lines with hydrates can cause a serious well-control problem. We conducted an up-to-date review of the drilling practices and mud formulations applied in deepwater drilling as related to gas-hydrate control and mitigation. The review indicated that salt/polymer mud systems are the most commonly used mud formulations in the Gulf of Mexico, North Sea, and offshore Brazil. Successful drilling with these systems has been achieved to water depths of up to 7,500 ft.

In the second part of this work, we measured the hydrate-phase equilibrium of 25 drilling-fluid formulations. Testing also included two new spotting-fluid formulations. Testing results indicated that, on weight basis, NaCl is the best thermodynamic inhibitor among the salts tested in this work, which are NaBr, Na-formate, KCl, and CaCl2. Although the high solubility of the Na-formate makes it possible to increase hydrate suppression beyond that of NaCl, the former is less effective on weight basis than NaCl. The glycols are considerably less effective inhibitors, on weight basis, than the salts. However, a greater degree of suppression can be achieved by using mixtures of salts and glycols. Among the tested glycols, ethylene glycol showed the best performance compared to Aqua-Col™S, Geo-Meo™ D207, and HP-100N™.
Integration of NMR With Other Openhole Logs for Improved Formation Evaluation
Authors: Minh Chanh Cao , Freedman Robert , Crary Steve , Cannon Darrel
Published: December 2007

The recently introduced measurement of total porosity from nuclear magnetic resonance (NMR) tools can help to identify the hydrocarbon type and to improve the determination of formation total porosity (ϕt) and water saturation (Swt) in combination with other openhole logs. In shaly formations, porosities are difficult to estimate in the presence of hydrocarbons, especially those for gas and light oils. Water saturations are even more difficult to estimate because critical parameters such as clay cation exchange capacities/unit pore volume (QV), the formation factor (F) and formation water resistivity (Rw) might not be known. The latter quantities are essential inputs into the Waxman-Smits and dualwater model saturation equations.

In the typical case of shaly gas-bearing formations, both the total porosity corrected for the gas effect and the gas saturation (Sxgas) in the flushed zone can be derived by combining total NMR porosity (ϕNMR) and density porosity (ϕdensity). Adding resistivity logs such as Rxo and Rt helps to differentiate between gas and oil. Furthermore, the flushed zone water saturation (Sxot) computed from 1 − Sxgas can be used in many ways. One procedure uses Sxot in conjunction with the Rxo saturation equation to determine QV or F. Another technique uses Sxot in conjunction with the saturation point (SP) to estimate QV when Rw is known. Yet, another method estimates QV directly from the NMR short relaxation time part of the T2 distribution and use Sxot in conjunction with SP to estimate Rw. The new interpretation procedure follows the sequential shaly sands approach: first, determine porosity, second, determine shaliness, and, third, determine saturation. The new procedure improves on the classical method by offering new ways to compute QV, F and Rw. The methodology is applied to a number of field examples.
Examination of Seismic Repeatability as a Key Element of Time-Lapse Seismic Monitoring
Authors: Hughes J. K.
Published: December 2007

The propagation of elastic waves in rocks is determined by the bulk modulus, shear modulus, and bulk density of the rock. In porous rocks all these properties are affected by the distribution of pore space, the geometry and interconnectivity of the pores, and the nature of the fluid occupying the pore space. In addition, the bulk and shear moduli are also affected by the effective pressure, which is equivalent to the difference between the confining (or lithostatic) pressure and pore pressure.

During production of hydrocarbons from a reservoir, the movement of fluids and changes in pore pressure may contribute to a significant change in the elastic moduli and bulk density of the reservoir rocks. This phenomenon is the basis for reservoir monitoring by repeated seismic (or time-lapse) surveys whereby the difference in seismic response during the lifetime of the field can be directly related to changes in the pore fluids and/or pore pressure. Under suitable conditions, these changes in the reservoir during production can be quantitatively estimated by appropriate repeat three-dimensional (3D) seismic surveys which can contribute to understanding of the reservoir model away from the wells. The benefit to reservoir management is a better flow model which incorporates the information derived from the seismic data.

What are suitable conditions? There are two primary factors which determine whether the reservoir changes we wish to observe will be detectable in the seismic data:

the magnitude of the change in the elastic moduli (and bulk density) of the reservoir rocks as a result of fluid displacement, pressure changes, etc.; the magnitude of the repeatability errors between time-lapse seismic surveys. This includes errors associated with seismic data collection, ambient noise and data processing.

The first is the signal component and the second the noise component. Previous reviews of seismic monitoring suggest that for 3D seismic surveys a signal-to-noise (S/N) ratio of 1.0 is sufficient for qualitative estimation of reservoir changes. Higher S/N ratios may allow quantitative estimates.

After a brief examination of the rock physics affecting the seismic signal, we examine the second factor, repeatability errors, and use a synthetic seismic model to illustrate some of the factors which contribute to repeatability error. We also use two land 3D surveys over a Middle East carbonate reservoir to illustrate seismic repeatability. The study finds that repeatability errors, while always larger than desired, are generally within limits which will allow production-induced changes in seismic reflectivity to be confidently detected.
An Analysis of High-Velocity Gas Flow Through Porous Media
Authors: Firoozabadi Abbas , Katz Donald L.
Published: December 2007

Darcy's law is inadequate for representing high-velocity gas flow in porous media, such as near the wellbore. An analysis of pressure lost during flow through conduits of alternating cross sections suggests more appropriate words for describing the mechanism for energy loss and terms in the flow equation. Updated correlations are presented for the coefficient of the velocity-squared term.

Introduction

Much research has been conducted to understand flow through porous media. Regarding high velocity, suitable correlations and nomenclature are the subject of controversy because of different views on the mechanism causing pressure drop.

This study tries to improve the understanding of high-velocity flow through porous media. Using available data and this research, the best correlation is sought to permit the calculation of high-velocity flow based on permeability, porosity, and character of the rock. permeability, porosity, and character of the rock. We hope that a nomenclature can be suggested that is acceptable to both reservoir engineers and fluid mechanics research scientists. The results should be useful for improving correlations of gas-well flow data and for predicting well flow from core data, fluid properties, and specified conditions. properties, and specified conditions. Early Work on High-Velocity Flow

Fancher et al. measured pressure drop during flow through a large number of unconsolidated and consolidated porous media. They correlated the data by using the porous media. They correlated the data by using the friction factor and Reynolds number, with grain diameter as a characteristic length. They showed that for flow through porous media, an increased pressure drop at high velocity is beyond that proportional to velocity. Data taken at the USBM were correlated using a quadratic equation of pressure drop with the second term of velocity to the nth power. Green and Duwez increased the understanding of high-velocity gas flow data when studying sintered metals. They adapted the equation with a velocity term squared that Forchheimer had developed:

dp v- ---- = ----- + pv 2......................(1)dL k

Comell and Katz measured the porosity, permeability, and B factors for cores, resulting in a correlation of B with permeability. The term B was called a "turbulence factor," but the expression was unacceptable to several researchers.

Language Used in Literature

Space limitations prohibit quoting completely the language used when describing the mechanism that consumes energy at more than a linear rate with velocity. The term used in flow equations (generally the in a quadratic flow equation) also has been given various names according to the author's view of the flow mechanism.

Table 1 assembles selected typical titles and statements quoted from published works. After the flow mechanism has been reviewed, a more appropriate language will be submitted to agree with the concepts developed here.

JPT

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