bluuebunny/crossref_metadata_2025 huggingface dataset:
Pressure Behavior of a Hydraulic Fractured Well in Tight Gas Formation with Threshold Pressure Gradient
Authors: Lu Jing
Published: June 2014

The threshold pressure gradient, which is associated with non-Darcy flow in low permeability tight gas formation, is defined as the level of pressure gradient that has to be attained to enable the fluid to overcome the viscous forces and start to flow. With low velocity and non-Darcy flow, the fluid flow boundary is controlled by the threshold pressure gradient and can extend outward continuously, while the fluid beyond this boundary cannot flow.

This paper presents analytical solutions to the pressure transient equations of a uniform-flux hydraulically fractured gas well in tight gas formation with threshold pressure gradient. These solutions are obtained by using Green's functions method with numerical approximations. A method to determine the location of the moving boundary front is also presented.

This paper concludes that the pseudopressure equalpotential surfaces for a fully penetrating vertical uniform-flux hydraulically fractured gas well are a family of ellipse, whose focuses are the two endpoints of the hydraulic fracture. This paper also concludes that both pressure transient distance in the direction perpendicular to the fracture and pseudopressure drop at the wellbore are approximately linear functions of the square root of producing time. Finally, the solution procedure proposed in this paper is a fast tool to evaluate a hydraulically fractured gas well performance in tight gas formation.
Pinpoint Multistage Fracturing of Tight Gas Sands- An Integrated Model with Constraints
Authors: Yu Haiqing , Rahman M. M.
Published: June 2014

As the demand for gas increases worldwide, tight, deep and multilayered unconventional gas sands are becoming the target for development. For such reservoir the conventional approach of simple fracturing the formation to hydraulically stimulate the well is inadequate. Continuous progress in hydraulic fracturing technology results in pinpoint fracturing, which allows multiple precisely targeted sands to be stimulated. Recently, this technique has been used in the developmet of tight gas sands. However, the systematic design methods for fracture treatment parameters with constraints are not well presented in the literature. Even the most currently available commercial software lack proper optimization tools in them and they do not take into consideration several key parameters and realistic constraints in them. An integrated but constrained model to design pinpoint multistage fracturing treatment has been developed to maximize gas production from layered tight sands. Model couples both the industry experience and design parameters based on hydraulic fracture mechanics. This integrates reservoir in-situ parameters, fracture geometry, fracture treatment design, realistic design constraints, and production and economic models. The integrated model has been successfully applied to a hypothetical deeper and layered tight gas sands to demonstrate its merits. A parametric study is also conducted to compare between the conventional single-stage and pinpoint multi-stage hydraulic fracturing with their basic design concepts and post-fracture benefits. It is evident that the productivity increase is about 20-fold higher in pinpoint multistage fracturing compared to 6-fold for blanket fracturing. Insightful parametric sensitivity analyses are also presented. This model could also be used to study the potential of the deep UAE tight gas sands.
Production Forecast after Hydraulic Fracturing in Naturally Fractured Reservoirs: Coupling a Complex Fracturing Simulator and a Semi-Analytical Production Model
Authors: Cohen Charles-Edouard , Xu Wenyue , Weng Xiaowei , Tardy Philippe M.
Published: June 2014

The growing interest in exploiting shale resources is generating new technologies in fracture modeling and reservoir simulation. In the presence of pre-existing natural fractures, hydraulic fracture propagation and proppant distribution can be very complex. Developing the tools to understand fracture propagation and its link to production in shale reservoirs is one of the major technological challenges that the industry is facing today. These challenges are being addressed with new hydraulic fracture simulators and production models for complex hydraulic fracture networks in shale reservoirs. However, the coupling between these two technologies is not mature yet.

This paper presents a simple automated workflow from simulating hydraulic fracture propagation in naturally fractured reservoirs to the subsequent production. This work documents the coupling of an existing complex fracturing simulator with a new production model. The complex fracture model considers interactions with natural fractures, stress shadow effects and proppant placement. The production model is based on a semi-analytical approach applied to the discrete hydraulic fracture network. The analytical solution used to simulate the flow from the matrix into the fracture network is simple and well known, but it relies on the assumption of constant pressure in the fracture which can only be obtained with infinite fracture conductivity. An original feature of this model is an algorithm to extend the validity of the analytical solution to all fracture conductivities, by calculating a local "time delay" based on mass balance. The validity of this approach is illustrated by a comparison with results from a standard reservoir simulator. The simple automated workflow that combines the two simulators gives the opportunity to investigate the relation between production and fracture treatment design in naturally fractured reservoirs. This paper illustrates the application of the workflow to realistic cases and the sensitivity of several design parameters that affect well performance.
Hybrid Forecasting Methods for Multi-Fractured Horizontal Wells: EUR Sensitivities
Authors: Nobakht M.. , Clarkson C. R.
Published: June 2014

In this paper, the sensitivity of expected ultimate recovery (EUR) for horizontal wells with multiple fractures to decline exponent is studied using the simplified forecasting method introduced by Nobakht et al. (2010). This is very important from the reserves evaluation perspective due to uncertainty in decline exponent, b. This uncertainty is caused by many factors like adsorption and reservoir/completion heterogeneity. It is found that in case of time-based forecast (duration of forecast is specified), the ratio of EURs for two different specified values of decline exponent depends on the ratio of economic life time of a well to the duration of linear flow. On the other hand, this EUR ratio depends on the ratio of rate at the end of linear flow to economic rate limit for economic limit-based forecast (economic rate limit rate is specified).
Proper Selection of Surfactant Additives Ensures Better Well Stimulation in the Unconventional Oil and Gas Formations
Authors: Xu Liang , Fu Qiang
Published: June 2014

A typical assumption for promoting the use of surfactants is that traditional surfactants will work appropriately across a large gamut of fields, but our laboratory tests show that inappropriate application leads to much lower efficiency of the oil recovery and thereby diminished production. Operators must understand how surfactants extract the oil and then select surfactants cautiously in order to maximize recovery and minimize risk.

This paper presents a study on surfactant chemicals and their most relevant parameters. In particular, the key characteristic of surfactant additives in unconventional oil and gas formations was found to be the emulsion tendency. It was found that a weakly emulsifying surfactant was more capable of solubilizing and mobilizing additional oil globules via self association. In stark constrast to a conventional non-emulsifying surfactant, the correct application of a weakly emulsifying surfactant led to better well cleanup and a higher ultimate oil recovery.
A Scale-Model Study of Bottom-Water Drives
Authors: Henley D.H. , Owens W.W. , Craig F.F.
Published: June 2014

The oil recovery performance of systems producing entirely by bottom-water encroachment has been experimentally determined in a series of scaled laboratory-model tests. The effects of well spacing, fluid mobilities, rate of production, capillary and gravity forces, well penetration and well completion techniques on the oil recovery performance have been investigated. The laboratory tests were performed using two uniform, unconsolidated sand-pack models. The models have ratios of the interwell distance to the formation thickness of 12 and 2, respectively. Tests at constant total fluid production rate were performed simulating a range of uniform reservoir characteristics and operating conditions encountered in field operations. The performance was determined by material balance and by observation of the encroachment of dyed fluids into the models. The results of the model tests agreed with those obtained mathematically when the conditions previously considered in theoretical studies were simulated, that is, when the oil and water are of equal density and no capillary forces exist.

The model study of bottom-water drive indicated that certain variables can affect the oil recovery performance to a greater degree than can be predicted by present analytical methods. In one comparison, the oil recovery at a water-oil ratio of 20 (obtained at a wide well spacing) varied as much as threefold, depending upon the system's properties and the production rate. Lesser effect of mobility ratio and no effect of capillary forces over the range studied were observed. The test results also showed that the deeper the well penetration into the oil column, the greater the total water production to a producing WOR of 20. However, the ultimate sweep efficiency, and so the oil recovery to this level of WOR, did not vary significantly with well penetration. Horizontal fractures at the top of the formation did not significantly change the sweep characteristics of the reservoir models when values of radius and fracture capacity encountered in actual reservoirs were used. Impermeable pancakes at the bottom of the well moderately increased the oil recovery efficiency both at water breakthrough and at high water-oil ratios. A method is outlined by which the oil recovery performance of other uniform bottom-water drive systems can be estimated from the information obtained in these model tests.
Unconventional-Natural-Gas Business: TSR Benchmark and Recommendations for Prudent Management of Shareholder Value
Authors: Weijermars Ruud , Watson Steve
Published: June 2014

Stock-listed independents have played a leading role in the development of unconventional natural-gas resources in the United States and Canada. Shareholders have provided up to 57% of the total capital tied up in a representative panel comprising the 20 leading US and Canadian operators. The accumulated equity-financed capital also provided the collateral for the complementary 43% debt financing. Prudent management of shareholder value in unconventional-gas businesses is therefore essential for ensuring security of gas supply, not only in North America, but also in other countries with emergent unconventional gas plays. This study analyzes and benchmarks the working capital cycles in unconventional-gas companies. The working capital and cashflow cycles are compared with those of diversified oil and gas majors. The ability to accumulate retained earnings is generally much lower for unconventional-gas producers than for integrated majors. Unconventional-gas producers tend to grow their share capital by new issues and not from economic value added by profit from business operations. Although little or no asset value is built from economic profit, shareholder returns may still grow for unconventional-gas companies as long as investor expectations remain positive about future earnings. In contrast, shareholder returns in conventional-gas companies come from genuine economic value added in profitable business operations. The root cause of the weakness or absence of operational profits in unconventional-gas operations is a combination of low gas prices and well flow rates that are too modest to pay for the total cost of the unconventional-gas production. The operating margins for unconventional-gas companies are either close to zero or negative, but not for the integrated oil and gas majors, which have impressive cash margins even at globally suppressed gas prices. The benchmarks provided here help one to understand which parameters impact the financial performance of unconventional-natural-gas companies most significantly. Recommendations are formulated to avoid the destruction of shareholder value, and to instead maximize total shareholder returns (TSRs).
Field Results of Miscible-Displacement Program Using Liquid Propane Driven by Gas, Parks Field Unit, Midland County, Texas
Authors: Marrs Doyle G.
Published: June 2014

A miscible-displacement program utilizing a propane slug driven by residue gas has been in operation in the Parks field unit approximately three years. A total of 1,540,000 bbl of liquid propane was injected into 23 wells between June, 1957, and July, 1958. During July, 1958, residue gas injection was begun at an injection rate of approximately 10 MMcf/D. Gas has been injected at this rate to the present time, and cumulative gas injection to July 1, 1960, has totaled 6,871 MMcf. It is concluded at this time that the project can be declared an engineering success since field results indicate an oil bank has been created by a gas-driven propane slug. It is further concluded that the project will be an economic success insofar as additional oil recovery over primary is concerned. However, the project has not been in operation a sufficient length of time to declare it an economic success in regard to oil recovery over that which it is believed could have been obtained by water injection. The answer to this question is yet to be determined. It is estimated that the ultimate recovery of the oil originally in place would have been 17 per cent by primary depletion, 41 per cent by water injection and will be 55 per cent by propane-gas-water injection.

Introduction

Miscible displacement is an oil-recovery process which is rapidly gaining popularity inasmuch as the process recovers 100 per cent of the oil in place in the swept volume. In comparison, straight gas injection normally recovers only 45 to 55 per cent, and water injection recovers 60 to 70 per cent of the oil originally in place in the swept area. The Parks field unit is an early field-wide example of the slug-type miscible-displacement process wherein a slug of fluid is injected into the reservoir which is miscible with both the reservoir and displacing fluids. In the Parks project, the slug was composed essentially of propane, and the displacing fluid is residue gas which is miscible with the propane at the existing reservoir conditions. Laboratory tests indicate extremely high recoveries from the swept reservoir volume by the miscible-slug process, but this is only a partial answer to the economic applicability of the process in an actual reservoir. The final answer can only be determined by field tests. The two main questions which must be answered through field testing are the following. How much volume will be swept? What minimum-size LPG slug can be utilized and still maintain miscibility throughout the process? Obtaining answers to these questions were two of the many objectives considered in arriving at the decision to install a field-wide miscible-slug process of such magnitude as the Parks project.
Simplified Analysis Aids in Optimizing Drilling Factors for Minimum Cost
Authors: Wardlaw H.W.R.
Published: June 2014

This paper shows how the cost of the drilling operation per 100-ft drilled can be related directly to bit weight, rotary speed and hydraulic horsepower variations. This enables optimum drilling conditions to be determined in a rapid and concise manner. The paper also shows how data/or such calculations can be obtained quickly and accurately by the "drill-off" method suggested by Lubinski. Examples are given to illustrate the principles and methods used.

Introduction

The problem of drilling oil wells at lowest cost and hazard needs little introduction, since it has been with us virtually from the earliest days of our industry. With better understanding of the effect of the various factors of bit weight, rotary speed and hydraulic jet action, however, the problem has recently taken on a more scientific aspect, and engineers or groups of engineers have been assigned to study many of the facets of this problem not immediately apparent to the general observer. Moreover, the availability of better equipment and materials has enabled certain practices to be adopted which were hitherto impractical or uneconomic. This has paved the way for further efforts to reduce footage costs, and so on. The improvements to be made in drilling technology and cost reduction are by no means exhausted, and we still frequently hear of new records being set and new materials and equipment becoming available. Some of the analytical methods used by the author to assist in promoting faster and more economic methods of drilling, particularly in Venezuela, form the basis for this descriptive study.

Statement of Theory and Definitions

In a highly competitive industry, it is no longer permissible to regard penetration rate as the sole criterion for drilling efficiency. Every new technique, however spectacular, must nowadays be viewed in the cold light of whether it will eventually lead to lower cost per foot drilled. In the exposition which follows, therefore, actual drilling rates will play only a secondary role, and attention will be focused on the more important aspect of cost per foot drilled. Changes in drilling factors such as weight and rotary speed will be studied in the light of how they directly affect the cost of operations.
Novel Large-Hydrophobe Alkoxy Carboxylate Surfactants for Enhanced Oil Recovery
Authors: Lu Jun , Britton Christopher , Solairaj Sriram , Liyanage Pathma J. , Kim Do Hoon , Adkins Stephanie , Arachchilage Gayani W. , Weerasooriya Upali , Pope Gary A.
Published: June 2014

A new class of surfactants has been developed and tested for chemical enhanced oil recovery (EOR) that shows excellent performance under harsh reservoir conditions. These novel Guerbet alkoxy carboxylate (GAC) surfactants fulfill this need by providing large, branched hydrophobes; flexibility in the number of alkoxylate groups; and stability in both alkaline and nonalkaline environments at temperatures up to at least 120°C. The new carboxylate surfactants were recently manufactured at a cost comparable to other commercial EOR surfactants by use of commercially available feedstocks. A formulation containing the combination of a carboxylate surfactant and a sulfonate cosurfactant resulted in a synergistic interaction that has the potential to reduce the total chemical cost further. One can obtain both ultralow interfacial tension (IFT) with the oils and a clear aqueous solution (even under harsh conditions such as high salinity, high hardness, and high temperature with or without alkali) with these new large-hydrophobe alkoxy carboxylate surfactants. Both sandstone and carbonate corefloods were conducted, with excellent results. Formulations were developed for both active oils (contains naturally occurring carboxylic acids) and inactive oils (oils that do not produce sufficient amounts of soap/carboxylic acid), with excellent results.
Experimental Stress Analysis of Tool Joints
Authors: Gormley John F.
Published: June 2014

Introduction

Drill pipe, and the connections used to join the pipe together, have had a long history of development and improvement. With the growing use of high tensile-strength pipe, the rotary shouldered connections used to join the lengths of drill pipe have become more critical. Fatigue-type failures of rotary-shouldered connections, or tool joints, have become a cause of much concern to operators and manufacturers. Most fatigue tests on tool joints have been made on the basis of bending moment applied vs number of cycles, rather than on the basis of stress vs cycles. A desire to learn more about the nature of stress in a tool joint due to bending caused a rather intensive experimental study to determine what actually happens to cause fatigue failure. It was known that a tool joint with insufficient make-up torque was subject to early fatigue failure. Therefore, the establishment of the relationship between make-up torque and allowable bending moment would enable a testing engineer to better correlate the results of various tests. The problem of calculating the stress in a tool joint due to an applied bending moment was complicated by: the effect of unknown stress concentrations; the applicability of the well known formula S = Mc/I; and the question of whether to use the combined cross section of the pin and box in calculating the moment of inertia I.
The Characteristics of Relative Permeability Curves in Naturally Fractured Carbonate Reservoirs
Authors: Lian Peiqing , Cheng Linsong
Published: June 2014

In naturally fractured reservoirs, fractures are the main flowing channels, while matrix is the dominant storage space. The oil/water relative permeability curve for the fracture in this kind of reservoir is very important to water-injection field development. In this study, we conducted experiments on the oil/water relative permeability of carbonate cores from Kenkiyak oil field and compared the differences in relative permeability curves between natural matrix cores and artificial-fracture cores. After the fracturing process, the two-phase flow area of tested cores becomes narrower, the permeability of the equal-permeability point gets higher, the relative permeability curve rises or drops more rapidly, and the displacement recovery efficiency decreases. The stress-sensitivity characteristics of the relative permeability curves were also studied on the basis of experiments on naturally fractured cores. With increasing effective confining pressure, the irreducible water saturation increases, the residual-oil saturation changes slightly, the equal-permeability point moves downward, and the displacement recovery efficiency declines. Numerical-simulation results indicate that for a given recovery factor, the water cut would increase more slowly but ultimate recovery factor would decrease using the relative permeability curve under higher confining pressure. Therefore, the water injection should be operated when the reservoir pressure is relatively higher to maintain formation pressure during waterflooding and lower the impact of stress sensitivity accordingly.
Review on Materials for Corrosion Prevention in Oil Industry
Authors: Arora Anshul , Pandey Siddharth Kumar
Published: June 2014

Among the many challenges faced in production and refining of crude oil, corrosion stands out due to its potential impact and associated economic and safety concerns. The primary cause of corrosion is the presence of mineral acids such as hydrogen chloride formed by hydrolysis of salts present in crude oil. Currently, significant research efforts have been devoted to design and develop new materials and procedures to reduce the water content and neutralize the acids in crude. These efforts have resulted in development of new corrosion-proof materials for coating in pipelines, chemical reagents and surface active substances for neutralization of acids as well as breaking of emulsions. Anionic, cationic and non-ionic surface active reagents are reported to be effective in demulsification application. Particularly the amphiphilic block copolymers, such as polyetyleneoxide-block-polypropylene oxide are used globally for the process of demulsification. Various organic amines are used in the overheads of atmospheric columns for neutralization of acids. Numerous nitrogenated compounds are also used as corrosion inhibitors in different refining operations. HERCULES-30617, KEMLIX-1123X and DEOL-4241 are some of commercial names used for the purpose of corrosion inhibition.

Hence we are deeply motivated to review all the recent research progresses that will provide us the impetuous to analyze the existing shortcomings and design and develop new materials with possible applications in above mentioned areas.
Impact of Different SAGD Well Configurations (Dover SAGD Phase B Case Study)
Authors: Tamer Mohamed R. , Gates Ian D.
Published: June 2014

The volume of heavy oil and bitumen in the oil-sands deposits in western Canada is similar to that of conventional crude oil in the Middle East. This resource is immense but is difficult and energy intensive to extract because the viscosity of the oil is high, typically greater than 100,000 to 1,000,000+ cp at original reservoir conditions. Current commercial thermal-recovery processes used include steam-assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS). These methods are energy intensive, emit significant amounts of CO2 into the atmosphere, and use large volumes of water to recover the oil. In this work, the focus is on SAGD processes. It has been demonstrated that operating strategy can be altered to improve SAGD performance, but it is not clear how well configuration can be changed to improve recovery, energy intensity, thermal efficiency, water use, and flue-gas emissions. This paper examines the impact of position and geometry of steam injectors on the performance of steam-based gravity-drainage processes in a heterogeneous reservoir. Different injection-well configurations including single horizontal (typical SAGD), offset SAGD, and vertical/horizontal well combinations have been evaluated by using a detailed, 3D, geostatistically populated, large-scale thermal reservoir-simulation model derived from core-data examinations of the Dover pilot site. The research reveals how injection-well configuration impacts energy delivery to the reservoir, how it affects thermal efficiency, and how it changes the evolution of the steam-conformance zone and oil-flow dynamics in the reservoir. The results suggest that several vertical injectors have the potential to deliver steam more efficiently than a single horizontal injector.
Reliability and Uncertainty of Prediction of Dynamic Elastic Constants in Reservoir Rock
Authors: Nejati Hamid Reza , Ghazvinian Abdolhadi , Saemi Mohsen
Published: June 2014

The prediction of dynamic elastic constants of reservoir rocks is one of the most important aspects of petroleum engineering. In recent years, several studies have been performed for this purpose. Because of uncertainty and variability in natural materials, deterministic prediction of rock properties in the reservoir is not reasonable. The purpose of this study is to evaluate uncertainty in dynamic-elastic-constant prediction for reservoir rock. Dipole-shear-sonic-image (DSI) log data from one of the Saudi Arabian reservoirs are used to evaluate uncertainty in dynamic-elastic-property prediction. For this purpose, a multiple linear regression (MLR) is carried out to present an empirical equation for shear-wave (S-wave) velocity prediction. Then, probabilistic analysis using Monte Carlo simulation (MCS) is performed to evaluate the uncertainty and reliability in prediction of dynamic elastic constants (Young's modulus and Poisson's ratio). On the basis of the analysis, uncertainty and variability of rock elastic constants are considered, and the value of Young's modulus and Poisson's ratio in a special interval from the reservoir are determined with a certain probability. Finally, the impact of log-data parameters on the value of rock elastic constants in the reservoir interval is assessed.
Deep Ground Bed for Casing Cathodic Protection
Authors: Daly John P.
Published: June 2014

This paper deals with the application of a deep ground bed (1,000 ft) for casing cathodic protection. While several ground beds of this type have been used successfully in the cathodic protection of surface lines, this is the first attempt to control external casing corrosion with a ground bed located in the corrosive zone.

Early and incomplete data indicate favorable results, with certain minor mechanical problems still to be solved. Actual corrosion protection has not been determined, but field surveys correlate with anticipated equipment performance.

Introduction

Severe external casing corrosion has been apparent for years in the West Kansas area, more precisely through the Dakota sandstone, a large water-bearing reservoir. New casing has been known to fail within a year, and repair costs average $5,000 per failure. Since casing corrosion protection is a relatively new field and has frequently shown poor results, the majority of the wells drilled in this area are still without protection of any kind.

A cathodic protection program study indicated that conventional ground bed designs have three major disadvantages.Poor current distribution occurs along the casing string. The conventional rectifier-ground bed system involves burying numerous non-sacrificial anodes about 100 ft from the well head and some 10- to 20-ft deep. It is from these anodes that current is supplied to the casing. However, corrosion usually occurs opposite, water-bearing formations located at a remote distance from the ground bed. Logically, a large amount of current is ineffective in the protection of the corrosive areas.High top-soil resistances during dry seasons result in overdesign of equipment and expensive electric-power bills or insufficient current densities.Interference with surface equipment occurs. Since the immediate ground bed area is highly corrosive to all structures not electrically connected to the system, it is always time-consuming and expensive to locate and protect all buried equipment in the vicinity of the anodes.

The logical solution to these three problems is to locate the ground bed in the Dakota water, approximately 1,000-ft deep. Early investigation indicates that satisfactory results can be anticipated from this type installation.
Quantitative Properties From Drill Cuttings To Improve the Design of Hydraulic-Fracturing Jobs in Horizontal Wells
Authors: Ortega Camilo , Aguilera Roberto
Published: June 2014

The study proposes a method for quantitative determination of porosity, permeability, and rock-mechanics properties from drill cuttings of at least 1 mm. The porosity value is used for determining a brittleness index by implementing sonic-derived porosity theory and a dipole sonic log from an offset well. A new parameter is introduced in this work to give a quantitative value to microscopic observations related to natural-fracture features in drill cuttings. It is called “frac value” and in conjunction with the brittleness index and permeability constitutes the main result of the methodology: the cut log. Quantitative data extracted from drill cuttings are important because the amount of information collected in horizontal wells drilled through tight formations, including cores and well logs, is rather limited in most instances. This paper is based on a Canadian case study with implications for selecting optimum intervals for hydraulic fracturing in a tight gas reservoir. However, the method should also be suitable for global applications in all types of reservoirs (unconventional and conventional) where good-quality drill cuttings might be available. Data extracted from the previous steps are useful for multistage hydraulic-fracturing 3D simulation of horizontal wells. This provides additional information to stimulation designers for deciding where to initiate hydraulic fractures and how to optimize fracture spacing and fracture size per stage instead of considering a homogeneous reservoir volume throughout the whole lateral section. It is concluded that the proposed method provides a useful tool for evaluation of direct sources of information that are available in many cases (drill cuttings) but are rarely evaluated quantitatively. The proposed method allows improved design of multistage hydraulic-fracturing jobs in horizontal wells.
The Effect of Coil Design on the Performance of the Induction Log
Authors: Duesterhoeft W.C. , Hartline Ralph E. , Thomsen H. Sandoe
Published: June 2014

The attenuation and phase shift which formations produce in the electromagnetic field of an induction-type electrical well-logging instrument are great enough to substantially affect the response of the tool to formation conductivity under normal logging conditions. The application of the general equations for the propagation of an electromagnetic field in a conductive medium to the transmitter receiver coil pair of an induction-logging-tool coil system gives an expression for the response which properly takes the propagation effects into account.

A comparison of a calculation of this type with the response computed from the commonly used geometric factor concept, which does not include the propagation effect, leads to a factor G representing the ratio of the responses computed by the two methods. The value of G decreases not only with increasing formation conductivity, but also with increasing transmitter-to-detector coil spacing. For a single coil pair with a 40-in. spacing, the value of G is 0.972 in a 20-millimho/m formation. The value is reduced to 0.915 and 0.812 for conductivities of 200 and 1,000 millimhos/m. As a result, the basic signal generated by the induction-logging coil system is not linearly related to formation conductivity as expected from the geometric factor concept. A uniform conductivity scale can be obtained only by adding a suitable nonlinear element to the recording system. The addition of auxiliary coils, having spacings less than the main-coil span, to achieve focusing results in an even greater departure of the basic signal from linearity with conductivity.

The solution of the field equations near the interface between two formations of different conductivity gives the curve shape on an induction logging tool in crossing the interface. The addition of auxiliary coils to achieve focusing can add anomalous character to the curve shape in crossing the interface, which might be mistaken for lithological detail.

Preliminary calculations which include the propagation effects in the determination of the conductivity correction for thin beds lead to correction factors which are substantially smaller than those obtained from geometric factor considerations. It is apparent that thin-bed corrections derived from geometric factor calculations are of doubtful validity.
Benchmarking of Biocidal Chemistries for the Control of Corrosion Biofilms
Authors: McGinley Heather R. , van der Kraan Geert M.
Published: June 2014

Description of the Material Corrosion-associated biofilms found in oilfield pipelines are complex systems that typically form anaerobically under turbulent flow conditions, consume the metal substrate on which they form, produce hydrogen sulfide, and often have corrosion products or waxes embedded in their extracellular matrices. A model pipeline has been constructed in the laboratory to approximate these conditions. The development of this laboratory capability has enabled the screening of a series of biocides as treatments for corrosion-associated biofilms in a seawater system.

Application Corrosion in general is a constant concern in production and transmission systems, and the carbon steel pipelines that carry water, mixed phases, or water-laden hydrocarbons, are especially at risk for microbiologically influenced corrosion (MIC). The presence of water and nutrients encourages the propagation of bacterial communities and the formation of biofilms, especially on internal surfaces of pipelines. Once these biofilms are established they can quickly develop into breeding grounds for pitting corrosion. In order to control MIC, it is essential to have a method, such as properly applying an effective biocide, to control corrosion biofilms.

Results, Observations, and Conclusions The benchmarking process identified candidate chemistries that are effective at killing biofilm-associated bacteria in the model pipeline system. Further testing suggested that a periodic slug dose can help to kill and remove biofilm while preventing undesirable increases in planktonic cells and hydrogen sulfide levels. These results and treatment recommendations will be discussed in this paper.

Significance of Subject Matter The benchmarking results indicate that corrosion biofilms can be effectively treated with biocides. Guidelines have been established for the effective dosing of these formulations to help control MIC in pipelines, and will be presented herein.
Mobility Control With Polymer Solutions
Authors: Gogarty W.B.
Published: June 2014

With the use of polymer solutions in secondary recovery operations, the need has developed to understand the mobility control mechanism. This study investigated mobility control by considering both permeability and rheological effects. Experiments used a high molecular weight, partially hydrolyzed polyacrylamide polymer. Flow studies took place in reservoir and Berea cores having zero oil saturation. Effective size of the polymer flow unit was inferred from Nuclepore filter tests. Clay studies indicated the particle size capable of decreasing the core permeability. Flushed permeabilities measured the approximate core permeabilities with flowing polymer solutions. These permeabilities were considerably lower than original values. With mobility data and the flushed permeability, maximum effective viscosities were determined for polymer solution flow in a core. Effective viscosities showed that rheological properties play an important part in mobility control with polymer solutions.

The study showed that permeabilities decrease and stabilize with polymer flow. At the lower permeabilities, high shear rates exist in the cores. Because of the pseudoplastic character of the polymer solution, the high shear rates caused low effective viscosities. This condition pointed to the inefficient use of the potentially high viscosity of the polymer solution at low shear rates.

Introduction

In the oil industry, a great deal of interest is being shown in the use of polymer solutions for secondary recovery and a number of polymer floods are being performed in the United States. Some of these floods have become commercial while others have been reported as failures. A number of floods are still in progress and remain to be evaluated. With the advent of polymer flooding, the need developed to understand the mobility control mechanism in porous media.
Metocean and Oil Spill Modeling
Authors: Michel C. , Quiniou V. , Vigan X.
Published: June 2014

This paper sets out to explain the global methodology developed by Total to improve the reliability of oil spill drift modeling by developing metocean skills in-house.

The role of oil spill modeling is not at present considered essential during an oil spill, despite the fact that its advantages have been clearly identified. Actually, model predictions should make it possible to –Forecast the drift of an oil slick–Identify the areas where the intervention teams should take action–Predict the period and areas that could be impacted–Inform neighboring installations, authorities and NGOs.

Oil & Gas Companies initially showed great interest in this new tool but, due to a series of poor modeling results, its place in the oil spill response was redefined. After several studies, these controversial results appear to originate in the questionable reliability of the current and wind data. To remedy this, Total created a "metocean & oil spill modeling" system to improve the quality of this data, which in turn will bring an improvement to oil-spill drift modeling results.

This paper explains the main steps of this system and details its advantages.

Its overall functioning has been tested in Total on a recent event: a gas and condensate leak on the Elgin platform in the North Sea. The main actions and conclusions are developed in this paper.

A retrospective analysis of the results on the Elgin event shows the system is effective, since the reliability of the predictions is estimated to be about 92% for the first day's forecast and about 77% for 2 days. So now, thanks to the improvements in metocean information, oil spill models can be considered as reliable tools for use in oil spill response.
Hydraulic Fracture - Field Test to Determine Areal Extent and Orientation
Authors: Reynolds J.J. , Scott J.B. , Popham J.L. , Coffer H.F.
Published: June 2014

This paper concerns field experiments to define the areal extent, orientation and thickness of an artificial fracture in the Sacatosa field, Maverick County, Tex. The fracture was made by a sand-oil treatment of 176,000 gal of lease crude containing a fluid-loss additive and 270,000 lb of 20–40 mesh subangular Poteet sand. The well was perforated with a jet gun, consisting of six shots in a single plane. Fourteen test holes were drilled at various locations around the fractured well. Drill-stem tests, Micro and Sonic Logs, coring and sampling of formation cuttings were used to determine the presence of the fracture in these holes. The test holes were drilled at distances up to 250 ft in a radial pattern around the fractured well. In addition to fracture areal extent and orientation, sand grain size before and after fracturing, erosion of perforations and fracture thickness were studied.

Introduction

The orientation, areal extent and thickness of artificially induced fractures in reservoir rock by hydraulic means have been discussed in great detail in the oil industry in recent years. Methods for initiating vertical and horizontal fractures have been tested in the laboratory and the field. Although the methods used give successful well stimulation, good field data on the physical characteristics of the fracture are lacking in the literature. It is recognized generally that properties of a fracture, such as thickness, sand placement in the fracture and shape, may vary from reservoir to reservoir. This paper gives data on size, orientation and sand placement in a large fracture initiated in a single plane in Sacatosa field, Maverick County, Tex. It is not intended as a speculative study; rather, it is restricted to actual field data on fracture properties. No attempt is made to prove that the same type of fracture occurs in all wells.
Identification, Classification and Prediction of Reservoir Nonuniformities Affecting Production Operations
Authors: Hutchinson C.A. , Dodge C.F. , Polasek T.L.
Published: June 2014

A study of sandstone outcrops typical of producing horizons has been undertaken to develop a method for predicting the size, shape and permeability contrast of reservoir nonuniformities. This paper is a progress report and presents the tentative conclusions reached from the study of several Cretaceous age outcrops in the Four Corners area and of the Woodbine outcrop around Dallas.

The results to date suggest that nonuniformities in sandstone reservoirs may be classified according todepositional environment androck texture and cement content.

Within a sandstone unit, there will be no drastic variations in permeability providing the cement content is not sufficient to control the permeability. For this noncement-controlled or texture-controlled permeability situation, up to a 5:1 ratio of maximum-to-minimum permeability is expected for measurements on 1 x 7/8-in. core plugs. When the permeability of the sand is cement-controlled, the maximum-to-minimum ratio of permeability values within a sand unit may exceed 100:1.

Clean shale sections tend to be continuous over great distances, whereas sandy shale sections will be fairly continuous only in ripple-marked and horizontally bedded layers of the formation. In cross-bedded sandstones, the sandy shale sections will tend to be discontinuous.

The conclusions reached in this study so far suggest that, if the bedding, textural qualities and cement content are known in blanket sandstones, the sizes, shapes and permeability contrast of nonuniformities within the sandstone are predictable. The bedding, textural properties and cement content can be determined from well cores.

Introduction

This is a progress report on a major research study that is far from completion. The report is presented with the hope that the limited accomplishments to date may impart worthwhile insight to some and that others of the industry will become sufficiently interested in this frontier of technology to lend their efforts to developing an understanding of reservoir nonuniformities and the engineering procedures for including their effects in reservoir performance.
Industrial Cogeneration Appliance--An Example of a Drilling Rig
Authors: Radišic Ognjen , Radišic Mladen , Maksimovic Rado , Radakovic Nikola
Published: June 2014

Focusing on one branch of heavy industry (deep oil and gas drilling) in our work, we come to the importance of energy efficiency, or rather to the problem of energy-efficiency increase. In this paper, some major issues in the field have been highlighted, including the energy potentials in drilling rigs and a proposal on how to increase energy efficiency by applying cogeneration to diesel engines within the scope of the contribution to rational use of energy potentials.
Field-Scale Simulation of Cyclic Solvent Injection (CSI)
Authors: Chang Jeannine , Ivory John
Published: June 2014

Only 5-10% of the oil in Lloydminster heavy-oil reservoirs is recovered during cold heavy-oil production with sand (CHOPS). CSI is currently the most active post-CHOPS process. In CSI, a solvent mixture (e.g., methane/propane) is injected and allowed to soak into the reservoir before production begins (Fig. 1). CSI has been focused on heavy-oil recovery from post-CHOPS reservoirs that are too thin for an economic steam-based process. It has been piloted by Nexen and Husky and was a fundamental part of the CDN40 million joint implementation of vapour extraction (JIVE) solvent pilot program that ran from 2006 through 2010. This paper describes field-scale simulations of CSI performed with a comprehensive numerical model that uses "mass-transfer" rate equations to represent nonequilibrium solvent-solubility behaviour (i.e., there is a delay before the solvent reaches its equilibrium solubility in oil). The model contains mechanisms to consider foaming or to ignore it, depending on the field behaviour. It has been used to match laboratory experiments, design CSI operating strategies, and to interpret CSI field pilot results. The paper summarizes the impact on simulation predictions of post-CHOPS reservoir characterizations where the wormhole region was represented by one of the following five configurations: (1) an effective high-permeability zone, (2) a dual-permeability zone, (3) a dilated zone around the well, (4) wormholes (20-cm-diameter spokes) extending from the well without branching, and (5) wormholes extending from the well with branching from the main wormholes. The different post-CHOPS configurations lead to dramatically different reservoir access for solvent and to different predictions of CSI performance. The impacts of grid size, upscaling, solvent dissolution and exsolution rate constants, and injection strategy were examined. The assumption of instant equilibrium solubility resulted in a 23% reduction in oil production compared with when a delay in solvent dissolution and exsolution was allowed for. Increasing the gridblock size by a factor of nine reduced the predicted oil production five-fold. Assuming isothermal behaviour in the simulations decreased predicted oil production by 17%.
How To Assess a Depth of Permeability Impairment of the Wellbore Zone Using Drillstem-Testing Flow-Period Data
Authors: Szpunar Tadeusz , Budak Pawel
Published: June 2014

This paper provides a simple procedure for evaluation of depth of permeability impairment within the wellbore zone using drillstem-testing (DST) flow-period data. Also computed are skin factor, permeability of the wellbore zone, and permeability of the reservoir. Contrary to the type-curve-fitting method, straight-line approximations were used to compute these values. All calculations presented are for "real-world" data.