bluuebunny/crossref_metadata_2025 huggingface dataset:
Automated Reservoir Model Selection in Well-Test Interpretation
Authors: Güyagüler Baris , Horne Roland N. , Tauzin Eric
Published: December 2007

Technological achievements in the area of well testing, such as permanent downhole gauges, demand automated techniques to cope with the large amounts of data acquired. In such an application, the need to interpret large quantities of data with little human intervention suggests the desirability of automated model recognition. Also, in some cases, the characteristic behavior of the pressure or its derivative curves for specific models may be hidden behind noise, or human bias may lead to the selection of an invalid or inappropriate model.

This paper demonstrates an approach based on a genetic algorithm (GA) that is able to select the most probable reservoir model from among a set of candidate models, consistent with a given set of pressure-transient data. The type of reservoir model to be used is defined as a variable and is estimated together with the other unknown model parameters (permeability, skin, etc.). Several reservoir models are used simultaneously in the regression process. GA populations consist of individuals that represent parameters for different models. As the GA iterates, individuals that belong to the most likely reservoir model dominate the population, while less likely models become extinct. Because different models may require different numbers of parameters, the solution vectors have varying lengths. The GA is able to cope with such solution vectors of differing size. Information exchange (GA crossover operator) is allowed only between parameters that are physically related.

Alternatively, we illustrate the use of the GA as a preprocessor for conventional gradient-based algorithms such as Levenberg-Marquardt.1 When combined with the GA, the dependency of such conventional algorithms on the initial guess is reduced, and the overall regression performance is improved. For automated interpretations in which the model is already known, this method allows us to eliminate the initial guess-determination step.

Tests on real and synthetic pressure-transient data indicated that the proposed method was able to select the correct reservoir model. The method revealed hidden implications of the pressure transient that may otherwise have been overlooked because of noise. As a preprocessor for more conventional nonlinear regression approaches, applying the GA to a number of noisy pressure-transient tests demonstrated that the method is robust and efficient.
Novel Thermal Process for Recovery of Extremely Shallow Heavy Oil
Authors: Osterloh W. Terry , Jones Jeff
Published: December 2007

In this paper, we propose a new process for the recovery of heavy oil from sands at depths of 100 ft or less and report its feasibility as determined by reservoir simulation. The process, called blanket heating, recovers oil by the traditional mechanisms of viscosity reduction and gravity drainage; however, it avoids the problem of handling large volumes of injected fluids and reduces the risk of surface emissions that would occur with typical steam enhanced oil recovery (EOR) methods.

Simulation results indicate that excellent, thermally efficient oil recovery is possible. Process sensitivity to many critical parameters was determined.
Improved Drilling Performance With Enhanced Crossflow Rock Bits
Authors: Allen James H. , Baker William
Published: December 2007

After review of the literature on drilling hydraulics and evaluation of two-nozzle drilling, specially designed two-nozzle enhanced crossflow rock bits were manufactured and tested. Performance analysis indicates a 12 to 16% increase in drilling rate over standard three-nozzle jet bits. Laboratory and preliminary field test results are presented.

Introduction

Many drilling people are not aware of the number of successful and unsuccessful field tests conducted in the last 15 years on special bits designed to improve bottomhole cleaning. Many of the successful test bits were not reported or offered for standard field usage because drilling cost reductions were negated by increased bit development and manufacturing costs. Today, drilling costs have risen to a level where a slight increase in drilling rate performance will result in sizable cost savings.One basic hydraulic improvement was made when jet nozzles were incorporated into bit design in the late 1940's. Surface equipment requirements changed, and a period of drilling hydraulics study commenced. Most drilling people are aware of several studies and articles published on the subjects of bottomhole cleaning, chip-removal forces, crossflow, extended-nozzle bits, and two-nozzle bits.

Review of the Literature

A basic relationship of nozzle flow and crossflow on an impingement plate was deduced by Poreh and Cermak. The resulting crossflow, Vc, was directly proportional to the square root of the product of flow volume through a nozzle and the nozzle velocity.McLean, in studies conducted in 1964 and 1965, concluded that maximizing crossflow should produce the maximum use of available bit hydraulic horsepower. These studies included laboratory tests which measured crossflow distribution resulting from jet impingement on an actual rock bit. McLean determined the relative crossflow velocity at various points on the hole bottom due to jet impingement. The velocity parallel to the hole bottom at various locations was

(1)

where

Vc = crossflow velocity, ft/s (m/s), k = geometric constant, Q = nozzle flowrate, gal/min (dm3/min), V = nozzle velocity, ft/s (m/s), and D = bit size, in. (cm).

For the normal range of flow rates used in rotary drilling, the maximum crossflow will occur at the maximum bit hydraulic horsepower condition.In 1971, Sutko and Myers concluded that hole cleaning and drilling rate should improve as the number of nozzles is decreased. Hole cleaning and drilling rate should improve as nozzle standoff decreases.

JPT

P. 1687＾
Increasing Injectivity of Shaly Sands With Chemicals
Authors: Chakravorty S.K. , Gateman J.C. , Bohor B.F. , Knutson C.F.
Published: December 2007

The Viking sandstone reservoir, Coleville-Smiley field, Saskatchewan, Canada, is very shaly and water sensitive. The proven sources of injection water in the area are relatively fresh and in laboratory tests quickly plug tile Viking cores. After screening a large number of chemicals in the laboratory, a two-stage treatment was developed that maximized water permeabilities in core plugs. The purpose of the treatment was to restrict or inhibit clay swelling, prevent bacterial growth and increase injectivity. No one chemical was found that could do all these jobs well, so a three-component system was used: potassium chloride, polyoxyethylene triethylenediamine and an imidazoline. The optimum laboratory technique was to use a spearhead containing a high concentration of the treating chemicals followed by continuous treatment of the injection water with these material.

Introduction

The Eureka Viking sand pool is located in Southeastern Saskatchewan, about 200 miles northwest of Regina, 50 miles east of the Alberta-Saskatchewan border, and 200 miles north of the International Boundary (Fig. 1). The pool is located on the western end of the Dodsland field and is approximately 15 miles east of the Smiley-Dewar Viking sand pool. These two pools are within the Coleville-Smiley field boundaries as defined by the Saskatchewan Dept. of Mineral Resources. The producing formation of these pools is the Viking sandstone found at a depth of approximately 2,300 ft. The discussion presented in this paper pertains only to the Viking formation. Production was first established from the Viking sandstone in this area in Sept., 1953, with the discovery of the Smiley-Dewar pool. Discovery of the Eureka pool followed in 1954 and production was established for the Dodsland field in 1958. These fields presently contain approximately 650 wells capable of production from the Viking sandstone. The Viking sand is continuous throughout this area and the oil is found in the lows or valleys of the structure. Gas caps are located between the Eureka and Smiley-Dewar pools and along the northern edge of the Dodsland field. The name and location of the well selected for the injectivity test is HB Coleville 4-26-31-23 (lsd 4-26-3 1-23 W3M) in the Eureka Viking sand pool (Fig. 2). Other pilot water injection wells are located in lsds 11-6-31-22 W3M, and 12-7-31-20 W3M in the Dodsland field, lsd 9-4-31-25 W3M, and a four-well five-spot pilot injection on section 17-31-25 W3M in the Smiley-Dewar pool.

Geology and Reservoir Characteristics

The Viking member of the Colorado formation is of lower Cretaceous age. It consists of gray, silty shale beds and thin beds of chert pebbles. The lower 30 ft of the Viking member, consisting of medium-grained shaly sand, is known as the Viking sandstone. Structurally, the Viking member reflects the Paleozoic erosional surface by its highs and lows.

JPT

P. 1107ˆ
An Investigation of the Role of Capillary Forces in Laboratory Water Floods
Authors: Perkins F.M.
Published: December 2007

Introduction

Capillary forces play a controlling role in waterdrive displacement processes both in laboratory experiments and in actual reservoirs, but their quantitative importance may be quite different in the two cases. Because of the importance of conducting laboratory experiments which are representative of field conditions, it is necessary to understand exactly the role of capillary forces in the displacement process. Though a number of experimental investigations related to this subject are contained in the literature, there appears to be a lack of information pertaining to unsteady-state experiments in water-wet media. This experimental study was conducted to obtain additional laboratory data to clarify further the role of capillary forces in both the macroscopic and microscopic flow of oil and water in porous materials.

Theoretical Considerations

The capillary pressure is defined as the difference in pressure between a continuous oil phase and a continuous water phase in a porous material. The magnitude of this pressure difference depends on the interfacial curvature and the interfacial tension. The interfacial curvature is determined by the geometry of the pore spaces, the wettability of the rock surfaces, and the quantity of each phase present. Capillary forces are involved in a water-drive displacement process in that they exert a controlling influence on the microscopic fluid distribution which in turn is reflected in the saturation or macroscopic flow behavior.

Microscopic Fluid Distribution

Because of the microscopic nature of the displacement of oil by water, it is necessary to consider the flow and the fluid distribution in individual pores. On this microscopic scale the capillary forces, which act over a distance of one or two sand grain diameters, control the distribution of oil and water under static equilibrium conditions. When an external force is applied to the fluids, such as in a water-injection experiment, the applied forces tend to distort the oil-water interfaces. However, in most fine-grained, water-wet sands, the applied pressure difference across one or two grain diameters is usually several orders of magnitude less than the capillary pressure difference.
Stability and Failure of Sand Arches
Authors: Bratli Rolf K. , Risnes Rasmus
Published: December 2007

When producing from an unconsolidated sand, sand arches may form behind the perforation opening. On the basis of a theoretical model, we have analyzed the stresses in the sand. The effect of flowing fluids has been studied, and criteria describing the stability and failure of the sand are given.

The arching phenomenon was studied in the laboratory. The experiments qualitatively reproduced the theoretical results. To the extent that comparison was possible, the quantitative agreement between theory and experiments was fairly good.
Taylor's Dispersion in Stratified Porous Media
Authors: Lake Larry W. , Hirasaki George J.
Published: December 2007

During 1953–54, Taylor showed that if a certain criterion is met the combined effects of the transverse profile of longitudinal velocity and transverse diffusion on a solvent slowly flowing through a tube will manifest themselves as a longitudinal diffusion phenomenon. A similar phenomenon exists in stratified porous media where the transverse profile of longitudinal velocity and transverse dispersion can produce an effective longitudinal dispersion, called Taylor's dispersion in this paper. Since this effective longitudinal dispersion is larger than the corresponding homogeneous longitudinal dispersion, the quantitative description of this phenomenon would be important to dispersion-sensitive EOR processes, such as surfactant or miscible flooding.

Taylor's dispersion will occur in two-layer porous media if a suitably defined dimensionless number is much greater than unity. When this condition holds, the effluent history of a constant-mobility equal-density miscible displacement is that of the same displacement in a homogeneous medium with increased dispersion. The resulting effective longitudinal dispersion may be derived analytically and verified numerically as a function of several media properties. The most important of these are system thickness and permeability contrast.

In multilayer media, when two adjacent layers have a large transverse dispersion number they behave as a single layer with suitably averaged properties. This observation suggests an algorithm whereby Taylor's dispersion may be extended to multilayer systems. The algorithm, or grouping procedure, gives effluent histories that are in agreement with numerical solutions to the continuity equation and allow properties of the resulting effective dispersion to be investigated. From the results of this work, Taylor's dispersion can offer an explanation for the large field-scale dispersion observed in tracer test studies. Moreover, it appears that the grouping procedure could indicate a method for obtaining layered reservoir models from core data.
Effects of Bit Hydraulics on Full-Scale Laboratory Drilled Shale
Authors: Tibbitts Gordon A. , Sandstrom John L. , Black Alan D. , Green Sidney J.
Published: December 2007

The effects of bit hydraulics while drilling shale with a standard three-cone bit are examined in this paper. Tests were conducted by drilling into large-diameter, intact shale samples at simulated downhole conditions in Drilling Research Laboratory's wellbore simulator. The shale samples were recovered from massive surface outcroppings and preserved for laboratory use. The effects of hydraulic horsepower from 20 to 400 hhp and bit weights from 20,000 to 50,000 lbm on rate of penetration are presented.

Introduction

Most deep shales and some intermediate shales found in the U.S. are typically "slow" drilling formations. Efforts to improve rate of penetration in shale have been performed in both field tests and small-scale laboratory investigations. Until recently, laboratory drilling studies on shale have been confined to microbit1 or single-cutter2 studies because the ability to obtain and preserve large, intact shale samples had not been developed. In addition, laboratory facilities where full-scale drilling tests could be conducted at simulated deep-well conditions did not exist.

Massive surface shale formations have been located and techniques have been developed to extract and preserve large-diameter, intact samples. With these samples and the ability to simulate full-scale drilling conditions, a systematic, technical approach was taken where the effects of drill bit hydraulics were examined while drilling shale at simulated downhole conditions.

Background and Definitions

The in-situ conditions of a typical deep wellbore and surrounding rock formation are illustrated in Fig. 1. The formation is subjected to overburden stress, confining stress, wellbore pressure, and formation pressure. As previously demonstrated,3–5 rate of penetration is influenced strongly by the bottomhole conditions and appears to be most sensitive to the differential pressure between the wellbore and formation. These effects, however, can vary widely depending on rock properties such as rock type, strength, density, permeability, and mud properties such as composition, filtration rate, viscosity, solids content, and particle size.6 Bit hydraulics - i.e., the means of removing cuttings from the hole bottom and cleaning the bit with the drilling fluid - are a key factor in improved bit performance. Bottomhole cleaning theories,7 microbit studies,8 and full-scale laboratory drilling experiments in hard, impermeable rock9 have shown the need for adequate bit hydraulics to maximize rate of penetration and avoid bit balling. Field tests with extended nozzles10 also have demonstrated great potential for increasing rate of penetration in certain formations with improved bit hydraulics. Some nondrilling laboratory studies have shown the effects of nozzle size on pressure distribution at the hole bottom.11
Evaluation of Shaly Clastic Reservoir Rocks
Authors: Fertl Walter H. , Frost Elton
Published: December 2007

Log-derived spectral gamma ray data have been correlated to core-derived Qv data (i.e., cation exchange capacity per total pore volume) in a Texas coast Tertiary sand, east Texas Jurassic sands, and an Alaskan elastic formation. Such correlations can be used to provide a continuous in-situ water saturation estimate in shaly sands based on the Waxman-Smits equation.

Introduction

Exceptionally few hydrocarbon-bearing clastic reservoir rocks are essentially free of clay minerals. The significant effect of the latter on important reservoir properties such as porosity, water saturation, and permeability and on most geophysical well log responses is well-established.In clastic reservoirs, various types of clay minerals may occur in dispersed, laminated, or structural form. The types of clay distribution, each with a differing effect on effective porosity, can be inferred from crossplots of well logs, visual study of cores, or detailed SEM investigations. The latter distinguish dispersed-clay occurrences such as discrete particles (patchy kaolinite), pore lining, and pore bridging (illite, chlorite, and smectite), each of which have a pronounced but different effect on reservoir permeability.Clay minerals may be characterized in several ways. Table 1 lists composition, density, hydrogen index, cation exchange capacity C ec, and distribution of potassium, thorium, and uranium based on spectral gamma ray information for some of the more common clay minerals.Furthermore, numerous log-derived clay content (shaliness) indicators are reviewed and discussed (Table 2). These techniques basically assume identical properties for clay present in clastic reservoir rocks and adjacent shales. However, this assumption is often unrealistic.With the advent of the Waxman-Smits model to calculate reliable water saturation in shaly sands, emphasis has been focused on log-derived evaluation of C ec per total pore volume, Qv. The novel application of spectral gamma ray data will be discussed in detail.

Water Saturation Calculation Models and Associated Parameters

Archie, in his classic empirical equation, relates formation conductivity Ct, formation-water conductivity Cw, and the formation resistivity factor F (a function of porosity phi and cementation exponent m) to the formation-water saturation Sw.

Ct =Sw CwF(-1),

where F= phi (-m).

Archie's equation satisfactorily applies to clean sands. The presence of clay minerals, however, has a detrimental effect on Sw calculations. Since such Sw results are often too pessimistic, several clay/quartz distribution models and Sw calculation concepts have been proposed.

JPT

P. 1641＾
Meeting the Challenge To Extend Success at the Pikes Peak Steam Project to Areas With Bottomwater
Authors: Wong Frank Y. , Anderson Don B. , O'Rourke J. Cameron , Rea Harley Q. , Scheidt Keith A.
Published: December 2007

This paper provides a field review of the Pikes Peak steam project, showing key performance indicators of cyclic steam stimulation (CSS) and steamdrive in non-bottomwater. To test development over relatively thin bottomwater (less than 5 m), various steam processes were given field trials. Field pilot results from vertical-well CSS, dual horizontal well gravity drainage, and a combination of vertical injectors/horizontal well producers are presented for comparison.

Based on field experience and numerical simulation input, CSS has been conducted successfully with economic steam/oil ratios (SORs) in areas with up to 4 m of bottomwater by injecting significantly larger steam slugs in what is termed a drive, block, and drain process. In thicker bottomwater, the ability to operate at constant pressure to prevent bottomwater influx confers an advantage on the horizontal well approach. Follow-up field-scale developments of some bottomwater areas are described. Numerical simulation results indicate that pressuring up of a depleted steamflooded zone is an optimum strategy for maximizing offset flank recovery. This is being implemented in the field by reinjecting produced vent gases.
Fractured-Well-Test Design and Analysis in the Presence of Non-Darcy Flow
Authors: Gil J. A. , Ozkan E. , Raghavan R.
Published: December 2007

The objective of this paper is to discuss the design and analysis of fractured-gas-well tests to account for non-Darcy flow within the fracture. The results and discussions are based on a semianalytical model. Guidelines and correlations are presented to enable engineers to design fractured-well tests whereby the magnitude of non-Darcy flow may be estimated and its effect minimized, if necessary. The effect of non-Darcy flow skin (or rate-dependent skin) is discussed in detail. A method is also presented to analyze fractured-well tests under non-Darcy flow conditions to estimate the non-Darcy flow coefficient, fracture conductivity, and reservoir properties. Unlike the conventional methods, this method does not require two tests at different production rates.
IMPES Stability: Selection of Stable Timesteps
Authors: Coats K. H.
Published: December 2007

An IMPES stability criterion is derived for multidimensional three-phase flow for black-oil and compositional models. The grid may be structured or unstructured. Tensor considerations are neglected. The criterion can be used to set the time steps in an IMPES formulation or as a switching criterion in an adaptive implicit model.

The criterion extends previous work by accounting for three-phase flow, including capillary, gravity, and viscous forces, with all the possible cocurrent and countercurrent flow configurations in a general grid. The criterion derivation uses stability theory to the limits of its applicability, augmented by numerical experimentation, including extensive 1D tests and numerous field study datasets.
Evaluation of Monte Carlo Methods for Assessing Uncertainty
Authors: Liu Ning , Oliver Dean S.
Published: December 2007

Uncertainty in future reservoir performance is usually evaluated from the simulated performance of a small number of reservoir models. Unfortunately, most of the methods for generating reservoir models conditional to production data are known to create a distribution of realizations that is only approximately correct. In this paper, we evaluate the ability of the various sampling methods to correctly assess the uncertainty in reservoir predictions by comparing the distribution of realizations with a standard distribution from a Markov chain Monte Carlo method. The ensemble of realizations from five sampling algorithms for a synthetic, 1D, single-phase flow problem were compared in order to establish the best algorithm under controlled conditions. Five thousand realizations were generated from each of the approximate sampling algorithms. The distributions of realizations from the approximate methods were compared to the distributions from the exact methods. In general, the method of randomized maximum likelihood performed better than other approximate methods.
A Natural Polymer-Based Cross-Linker System for Conformance Gel Systems
Authors: Reddy B. R. , Eoff Larry , Dalrymple E. Dwyann , Black Kathy , Brown David , Rietjens Marcel
Published: December 2007

This paper describes a material derived from natural sources that can be used to crosslink a variety of acrylamide-based polymers over a broad temperature range to produce gels for conformance applications.

Delayed crosslinked polymer systems have been used for many years in conformance applications. For the past decade, the most widely used system has been based on chromium (3+) crosslinked polyacrylamide. Organic crosslinkers, such as phenol/formaldehyde and polyethyleneimine (PEI) have also been used with a variety of polymers. However, these systems are being scrutinized by governmental agencies and have been scheduled for phaseout in some countries. Because of these issues, a single, environmentally friendly crosslinker that could be used with a variety of polymers over a broad temperature range was the focus of this study.

This paper details the laboratory development of an environmentally friendly, natural polyamine crosslinker system. This crosslinker can be used with a variety of polymers, such as polyacrylamide, AMPS/acrylamide, or alkylacrylate polymers. Gels ranging from stiff and "ringing" type to "lipping" gels have been obtained. The data illustrate a simple, commercially available system that can be applied to field operations. Potential crosslinking mechanism(s) of the system will be discussed.
Thickening Carbon Dioxide With the Fluoroacrylate-Styrene Copolymer
Authors: Xu Jianhang , Wlaschin Aaron , Enick Robert M.
Published: December 2007

The fluoroacrylate-styrene copolymer is the first associative thickener that has been identified for carbon dioxide. Fluoroacrylate is highly carbon dioxide-philic, enhancing the solubility of the copolymer in carbon dioxide. Styrene is relatively carbon dioxidephobic, but promotes viscosity-enhancing, intermolecular associations. The copolymer used in this study had a composition of 29 mol% styrene - 71 mol% fluoroacrylate, a number-average molecular weight of 540,000, and a polydispersity index of 1.63. The copolymer was sufficiently soluble in CO2 at typical reservoir flooding conditions to induce a significant increase in viscosity. Falling cylinder viscometry measurements at 298 K demonstrated that the viscosity enhancement of CO2 increased with increasing copolymer concentration, decreasing shear rate, and decreasing temperature. Mobility measurements of the fluoroacrylate-styrene copolymer-CO2 solutions flowing through 80 to 200 md Berea sandstone cores at superficial velocities of 0.00035 to 0.028 cm/s (1-80 ft/D) at 298 K also indicated that the copolymer was an effective thickener. At a superficial velocity of 0.00035 m/s (1ft/ D), the addition of 1.5 wt% copolymer increased the CO2 viscosity by a factor of 19 relative to neat CO2. Smaller increases in viscosity occurred at lower copolymer concentrations and higher velocities. These results demonstrate that it is possible to design a compound that can enhance the viscosity of dense carbon dioxide. Fluoropolymers are characterized by environmental persistence, high cost, and unavailability in bulk quantities, however. Therefore nonfluorous, inexpensive thickeners are currently being designed.
Mechanisms of Mineral Scale Inhibition
Authors: Tomson M. B. , Fu G. , Watson M. A. , Kan A. T.
Published: December 2007

An extensive study of adsorption and desorption isotherms of four phosphonates on barite or calcite are tested for a wide range of solution conditions (0 to 1 M NaCl, 0 to 0.1 M Ca, 0 to 0.33 M sulfate, and 4.6 to 6.4 pH). From these adsorption/desorption observations, it is proposed that the primary driving force for adsorption is related to simple hydrophobic repulsion from solution of a macroneutral molecule and not, as is generally presumed, some specific inhibitor-surface interaction. From the nucleation study, it is observed that the inhibitor needed to completely inhibit barite formation is approximately equal to 16% surface coverage. An equation to predict minimum inhibitor need is proposed based on this model and is compared with field observations. The range of predicted inhibitor concentrations is quite similar to what is observed in the field as a minimum effective dose even though it was derived by a completely independent calculation method.
Zero-Tolerance Program To Enhance Safety Awareness During Well-Service Jobs
Authors: Farooqui Mohammad A. , Saudi Mohamed M. , Al-Ghurairi Fadhel A. , Blanke Allen T.
Published: December 2007

Saudi Aramco has implemented an effective program to emphasize safety during the increasingly complex, rigless well-service jobs in its maturing oil fields and during development activities in its new gas fields. The need was heightened for a structured approach to safe execution of well-service jobs because of the increasing number of horizontal well completions, which pose a higher risk and require greater logistical support during rigless jobs, and the initiation of an aggressive deep gas development program.

The objective of the Zero-Tolerance Program is to complete all well-service jobs without incident, injury, or loss of resources while maximizing benefits and gaining knowledge to sustain the process of continuous employee development.

The program comprises four basic elements.

Human resources development. Planning. Safe and effective job execution. Post-job evaluation for continued excellence.

Although production engineers (PEs) generally follow various guidelines and procedures covered under these categories, the Zero-Tolerance Program has placed these critical factors in a formal, structured document to ensure effective and consistent implementation.

This paper covers details of these elements and discusses tracking and accountability procedures that ensure the program is effectively implemented. Aggressive implementation of this structured program among field personnel has greatly enhanced the awareness of safety-related issues during rigless well-service operations.
A Rigorous Formation Damage Skin Factor and Reservoir Inflow Model for a Horizontal Well
Authors: Furui Kenji , Zhu D. , Hill A. D.
Published: December 2007

In this paper, we present a new analytical model for formation damage skin factor and the resulting reservoir inflow, including the effect of reservoir anisotropy and damage heterogeneity. The shape of the damaged region perpendicular to the well is based on the pressure equation for an anisotropic medium and, thus, is circular near the well and elliptical far from the well. The new model can be used for various distributions of damage along the well, depending on the time of exposure during drilling and completion. The inflow equation for a damaged, parallel-piped-shape reservoir illustrates the importance of the ratio of the reservoir thickness to the drainage length perpendicular to the well on the influence of formation damage for horizontal well productivity. Our model gives a simple, analytical expression for determining this effect.
A Strategy for Attacking Excess Water Production
Authors: Seright R. S. , Lane R. H. , Sydansk R. D.
Published: December 2007

This paper describes a straightforward strategy for diagnosing and solving excess-water-production problems. The strategy advocates that the easiest problems should be attacked first and that diagnosis of water production problems should begin with the information already at hand. A listing of water-production problems is provided, along with a ranking of their relative ease of solution. Although a broad range of water-shutoff technologies is considered, the major focus of the paper is when and where gels can be effectively applied for water shutoff.
Reservoir Study of the Roosevelt Pool, Utah
Authors: Rohr Egon H.
Published: December 2007

The Roosevelt pool in the Uintah basin of North-eastern Utah produces a high pour-point, high paraffin content crude oil from limestones and sand stringers in the Green River formation at a depth of about 10,000 ft. Due to the low matrix permeability of the rock the productivity of the wells was found to depend upon fracture development. Total production to March 1, 1957, from nine wells was 1,669,000 bbl and current capacity production from six wells is 450 BOPD with 440 BWPD. Production to date has been as a result of fluid expansion coupled with some water encroachment.

Introduction and Geology

The discovery of oil in the Green River formation at Roosevelt by the completion of the Roosevelt Unit No. 1 in June, 1949, marked the first production in the Uintah basin from reservoirs of Tertiary age. This well was completed for a flowing potential of 1,633 bbl of oil and no water at a depth of 9,350 ft. Following the Roosevelt discovery, a number of other pools were discovered in the area, including Duchesne, Red Wash, Flat Mesa and Walker Hollow. At the top of this page is a map of the Uintah basin, which is a structural, topographic and sedimentary basin in Northeastern Utah covering an area of approximately 8,000 sq miles. On this map A marks the Roosevelt pool; B Duchesne pool; C Red Wash-Walker Hollow pool; D Gusher No. 1; E Bluebell Unit No. 1; F Flat Mesa pool; and G County pool.

All commercial oil production at Roosevelt has been obtained from the "D" zone of the Basal Green River. The Green River is a 4,000-ft section of well-bedded oil shales, marlstones, thin dolomites, limestones, and sandstones. The "D" zone is encountered in the lower 1,500 ft of the section with production from this interval being dependent upon a combination of structure, stratigraphy, and fracture development. The Roosevelt pool is located on a broad northwest-southeast trending nose, approximately 7 miles south of the Uintah basin synclinal axis. Fig. 1 presents a structure map of the area and Fig. 2 is cross section of the pool constructed from radioactivity logs. An extensive coring and testing program was followed at many wells in an effort to correlate and identify the pay zones. As shown by the cross section, two main intervals of production totalling approximately 125 ft in gross thickness have been observed, of which the upper has been the more important.
Modeling of Transient Cuttings Transport in Underbalanced Drilling (UBD)
Authors: Doan Q. T. , Oguztoreli M. , Masuda Y. , Yonezawa T. , Kobayashi A. , Naganawa S. , Kamp A.
Published: December 2007

Underbalanced drilling (UBD) holds several important advantages over conventional drilling technology. These include minimization of formation damage, faster penetration rate, and ability for evaluation of reservoir productivity during the drilling process. As UBD technology matures, it has also been used more and more in different applications. However, many aspects of UBD technology remain poorly understood. The model presented in this paper seeks to understand the mechanisms involved in the transport of cuttings in UBD.

The model simulates the transport of drill cuttings in an annulus of arbitrary eccentricity and includes a wide range of transport phenomena, including cuttings deposition and resuspension, formation, and movement of cuttings bed. The model consists of conservation equations for the fluid and cuttings components in the suspension and the cuttings deposit bed. Interaction between the suspension and the cuttings deposit bed, and between the fluid and cuttings components in the suspension, are incorporated. Solution of the model determines the distribution of fluid and cuttings concentration, velocity, fluid pressure, and velocity profile of cuttings deposit bed at different times.

The model is used to determine the critical transport velocity for different hydrodynamic conditions. Results from the model agree quite closely, qualitatively, with experimental data obtained from a cuttings transport flow loop at the Technology Research Center of the Japan Natl. Oil Corp. (TRC/JNOC)'s Kashiwazaki Test Field in Japan. These results show the importance of slippage in the formation of the cuttings deposit bed. The model is useful in evaluating the minimum flow rate for effective cuttings removal in UBD.
Assessing Uncertainty in Channelized Reservoirs Using Experimental Designs
Authors: Friedmann F. , Chawathé A. , Larue D. K.
Published: December 2007

It is well established that uncertainty exists in simulated recovery forecasts because of the ambiguity in the measurement and representation of the reservoir and geologic parameters. This is especially true for immature projects, such as deepwater reservoirs, where the high cost of data limits the information that is available to build reservoir models. We present two strategies based on Experimental Design (ED) to quantitatively assess this uncertainty in recovery predictions for primary and waterflood processes.

We apply the ED methodology to channelized sandstone systems because of their relevance to many deepwater projects. We choose to study synthetic geological analogs of channelized systems that are built from a panoply of relevant parameters while taking into account the uncertainty that exists in the estimation of their ranges. We use the results of this study to generate type curves with neural networks. The trained neural networks can be used to predict reservoir performance rapidly where field data are very limited. We discuss applications of this methodology on field cases from western Africa.
Pressure Maintenance by Fluid Injection in the North Pembina Cardium Unit No. 1
Authors: Groeneveld H.
Published: December 2007

The North Pembina Cardium unit No. 1, the largest unit in The Pembina field, Alberta. Canada. covers a surface area of approximately 45,500 acres and has been developed on 80-acre spacing. Socony Mobil Oil of Canada, Ltd. is the operator. The unit was formed in Sept., 1959 for the purpose of maintaining reservoir pressure by fluid injection in the Cardium reservoir using large injection patterns. The pressure-maintenance project consists of 32,700 acres under water flood and 12,800 acres under miscible flood. The pattern arrangement includes five 2.560 acre 41-spots for the miscible flood, surrounded by 320-acre inverted nine-spots for the water flood. The Cardium sand which is sporadically overlain by a conglomerate section is characterized by severe stratification. Basic reservoir data for different areas within The unit are presented. Reservoir performance for The miscible flood as well as for the water flood is discussed. Although the performance history is short it is evident that formation stratification has a dominant effect on the reservoir performance.

Introduction

The Pembina field is located in the Province of Alberta in Western Canada, about 70 miles southwest of the city of Edmonton, as shown in Fig. 1. This large field which now covers an area of approximately 616,000 acres, was discovered in 1953 by Socony Mobil Oil of Canada, Ltd. The reservoir is a stratigraphic trap producing from the Cardium sand at a depth of about 5,000 ft. Neither bottom water nor free gas has been found. The recovery of oil by solution-gas-drive mechanism has been estimated between 13 and 16 per cent of the original oil in place. About 65 per cent of the developed area of the field is under pressure maintenance by water flooding, miscible flooding or gas flooding. To facilitate the administration of allowables, the Alberta Oil and Gas Conservation Board has divided the pressure maintenance area into approximately 100 "projects". The largest project. is the North Pembina Cardium unit No. 1, covering more than 45,500 acres. Fig. 2 shows the outline of the North Pembina Cardium unit No. 1 and its location within the Pembina field. The unit was formed in Sept., 1959 for the purpose of pressure maintenance by fluid injection using large injection patterns for miscible flooding as well as for water flooding. The present design of pressure maintenance would not have been possible without unitization. There are 21 participants in the unit and participation is calculated based on 85 per cent pore volume and 15 per cent acreage. The unit is completely developed with 569 wells drilled on 80-acre spacing. Socony Mobil Oil of Canada, Ltd. is the operator of this large unit. The purpose of this paper is to summarize the basic reservoir data for the unit, and to present a discussion on the design and performance of pressure maintenance by water flooding and miscible flooding.

Geology

The geology of the Cardium reservoir in the Pembina field has been described in the literature.

JPT

P. 977ˆ
Mechanisms of Rapid Cooling and Their Design Considerations in Underwater Welding
Authors: Tsai C.L. , Masubuchi K.
Published: December 2007

Rapid cooling is an inherent problem in underwater welding. This paper discusses the basic understanding of cooling mechanisms during underwater welding and the effectiveness of various methods of reducing the cooling rate. Numerical results obtained from a computer analysis are used to discuss the design criteria and the effect of various parameters on the cooling rate.

Introduction

During the last several years, systematic research efforts on underwater welding have been made at the Dept. of Ocean Engineering of the Massachusetts Inst. of Technology. Most of the research programs were funded by the National Sea Grant Office of the National Oceanic and Atmospheric Admin. Some of the reports, theses, and papers have been published. The research programs have covered various subjects including basic research on mechanisms of underwater welding as well as development of new, improved processes. This paper discusses one subject: rapid cooling during underwater wet arc welding.* This paper has been prepared primarily from results obtained in research by Tsai.The major portion of Tsai's research is composed of extensive mathematical analyses of heat flow during underwater wet arc welding. A series of mathematical equations has been developed to analyze all pertinent phenomena involved: dynamics of bubble formation, heat-loss mechanisms, etc. Experiments were made to examine the validity of the analyses. Studies were made to investigate effects of various parameters (welding conditions, plate thickness, etc.) on cooling rates in weldments, especially in the heat-affected zone (HAZ). Studies also were made to evaluate the effectiveness of various methods of reducing the cooling rate.Since details of analytical and experimental results are included in Ref. 4, this paper presents a brief summary of the analysis and some experimental results. The emphasis of this paper is placed on information of practical importance.

Brief Summary of Cooling Mechanisms in Underwater Welding

The mode of heat transfer in underwater welding is quite different from that in air welding. The existence of dynamic bubbles during underwater welding induces a flow field around the welding arc. This water flow along with the agitation of bubbles carries the heat away quickly from the base material and causes the rapid cooling phenomenon. In this section, buble dynamics and heat-loss mechanisms are discussed.

Underwater Bubble Dynamics

Bubble generation due to the high concentration of heat in the arc and its departure and final collapse during the underwater arc welding process in the wet condition was investigated by a high-speed cinematography study at the Massachusetts Inst. of Technology.

JPT

P. 1825＾
Extreme Forces in Short-Crested Seas
Authors: Huntington S. W. , Gilbert G.
Published: December 2007

The overall wave force on a large structure in a real multidirectional sea does not occur in a single direction but is a vector randomly varying in magnitude and direction. Although existing theories enable us to calculate the extremes of the orthogonal components of force, the designer needs the extreme resultant or total force. A theory is presented for estimating the extremes of the resultant and is confirmed by experimental measurement.
Large Wire Rope Mooring Winch Drum Analysis and Design Criteria
Authors: Song K. K. , Rao G. P. , Childers Mark A.
Published: December 2007

Flange splitting (separation of the flange from the barrel) is the most common structural failure in large mooring winches. Conventionally designed winches have failed on a number of occasions when wire ropes 3 to 3.5 in. (7.6 to 8.9 cm) in diameter and up to 10,000 ft (3048 m) long were employed for mooring large construction barges and semisubmersible offshore drilling units. It is believed that this is due to improper approximation of the field loading patterns on the winch, inadequate knowledge of actual forces transmitted onto the flange and drum barrel of the winch, and/or defects in the structural joint between the flange and the drum barrel.

The available design methods are often empirical, modified, or extrapolated from work done a decade ago using very small wire ropes and drums. The application of these techniques to a multilayered winch using large-diameter wire rope has proved to be unrealistic. A method is presented to calculate the flange thrust load and the barrel external pressure for winches using large-diameter wire ropes. Also, a general guide for design and analysis of such winches and the effect of the lateral modulus of elasticity of wire rope on the reduction in the layer tensions is presented.
Design Methodology for Selection of Horizontal Openhole Sand-Control Completions Supported by Field Case Histories
Authors: Price-Smith C. , Parlar M. , Bennett C. , Gilchrist J. M. , Pitoni E. , Burton R. C. , Hodge R. M. , Troncoso J. , Ali S. A. , Dickerson R.
Published: December 2007

Reservoirs requiring sand control pose a major challenge for selecting a suitable completion method. Horizontal openhole completions have been successfully used in such reservoirs to eliminate sand production while maximizing productivity/injectivity and well deliverability throughout the expected life of the completion and minimizing risk and complexity.

Although horizontal, openhole, sand-control completions, ranging from preperforated/slotted liners to gravel packs, have been applied widely in the last decade and many case histories have been discussed in the literature, a systematic methodology for selecting these completion methods remains to be documented. It is the objective of this paper to propose such a design methodology by unifying the broad experience and understanding from a global, technically integrated perspective.

The paper first discusses a generalized and unified methodology for determining when to install sand control, what to install for sand control, and how to install it in horizontal openhole completions. Specific factors recognized as affecting "when" are in-situ stresses, pore-pressure decline (sand prediction), expected well life, production rate, hydrocarbon and well type, gross product value, sand tolerance capacity, environmental limitations, and intervention capabilities, while the integration of all these factors has an impact on the overall risk analysis. In addition to many of the previous factors, critical drivers affecting "what" are identified as wellbore architecture, reservoir lithology and petrophysical properties, and sandface equipment reliability. Additional parameters impacting "how" are reservoir drilling fluid, displacement and cleanup methodology, screen type, operational implementation/ assurance (risk management, operational timing, and location logistics), torque and drag analysis, and gravel-placement simulations.

Secondly, examples of this methodology are presented in detailed case histories pertaining to different types of horizontal, openhole, sandface completions, including slotted liners, standalone screens (including expandable), and gravel packs, as well as various integrated cleanup methods, along with a summary of the lessons learned by each company.