bluuebunny/crossref_metadata_2025 huggingface dataset:
Erodability of Partially Dehydrated Gelled Drilling Fluid and Filter Cake
Authors: Ravi K. M. , Beirute R. M. , Covington R. L.
Published: December 2007

Partially dehydrated-gelled drilling fluid and filter cake must be displaced from the wellbore annulus to achieve a successful primary cement job. A term ‘Erodability of drilling fluid’ is defined in this paper and was calculated from measured parameters in a large-scale test model. Differential pressures were measured in the annular space between the casing and a man-made, permeable formation and also inside the casing. Three different drilling fluids used in typical field operations were tested. Each drilling fluid was tested over a period of four days. Experimental data on erodability of drilling fluid filter cake is presented as a function of time, flow rate, and aging. A mechanism is proposed for the erosion of partially dehydrated-gelled drilling fluid and filter cake. Recommendations are given to improve the removal of partially dehydrated-gelled drilling fluid and filter cake and thus achieve a successful primary cement job in field operations.
Real-Time Well Control Advisor
Authors: Milner G. M.
Published: December 2007

A summary of the design, and design rationale, for a software Well Site Advisor (WSA) tool to prompt and train drilling personnel in taking well control actions is presented. Key features of the WSA are: (1) a seven state Kaiman filter to estimate (track) and predict well and influx parameters during well control. Estimated and predicted parameters include bottom hole pressure, volume of influx gas, volume of influx liquid, influx position, influx distribution, influx velocity (top and bottom), and expected future pressures and volumes; (2) CuSum analysis of errors between predicted and measured pressures and volumes to detect meaningful deviations indicating possible problems; (3) automated pattern recognition or classification of data trends; (4) expert system processing to finalize the diagnosis of problems and provide advice; and (5) graphical user interface and efficient coding to provide rapid data entry, interpretation, and processing.

The WSA system is the final product of DEA-49, a thirty-month study funded by the Drilling Engineers Association, to develop a real-time well control advisor tool. Prior prediction systems have usually been designed for well planning functions or post-kick control analysis and were not capable of responding to events as they occur during kick control operations. This system provides real-time computer capability to accurately process, predict, and interpret kick control surface measurements (e.g., drill pipe pressure, casing pressure, pit gain, drill string weight, and pump strokes per minute) so that automated problem detection, diagnosis, and advice are possible during kick control.

Test results, including simulations, test well data, and actual kicks while drilling, are very promising and are discussed.
Application and Development of 17½-in. Very Long Insert Roller Cone Bits To Drill Interbedded Lithologies
Authors: Patrick B. L. , Bond D. F. , Zahradnik A. F. , Mackie C. G. , Brown L. H.
Published: December 2007

Historically, several steel tooth bits have been required to drill the interbedded lithologies indigenous to much of offshore Australia, especially in the 17½" (444.5 mm) surface hole. Steel tooth bits, while exhibiting high rates of penetration in softer formations, tend to wear rapidly in the harder dolomites or limestone. The development of previous large diameter Tungsten Carbide insert (TCI) bits in the IADC 51X class provided sufficient wear and impact resistance, but resulted in inadequate rates of penetration.

This paper presents the history and problems of developing and applying extended length inserts and describes the development and performance of 17½" roller cone bits with very long inserts (up to 1" projection). The 17½ IADC 415 bits (also referred to as 41X) were designed to drill interbedded lithologies at high penetration rates while maintaining cutting structure integrity.

The development program, which included extending existing carbide technology, allowed one bit to consistently drill the entire 17½" section (up to 1500 m) with 100% improvement in penetration rates. This reduced drilling cost by $350,000 per well.
Application of New Glycol/Resin Differential Sticking Preventative
Authors: Bland R. G. , Micho W. T. , Howard H. J.
Published: December 2007

A new water-soluble polyglycol/asphalt product (PGA) is described which provides the permeability plugging advantages of traditional deformable resins over a broader temperature range as well as the lubricity of refined petroleum oils and traditional lubricants without the agglomeration and environmental problems. Laboratory results presented include particle size distribution, lubricity, "Cloud Point", toxicity, permeability plugging and HPHT dynamic filtration. Case histories documenting the use of PGA offshore in the Gulf of Mexico are included.
Accurate In-Situ Stress Measurements During Drilling Operations
Authors: Kunze K. R. , Steiger R. P.
Published: December 2007

This paper describes easily implemented field procedures for obtaining in situ horizontal earth stresses during drilling operations. The procedures were developed to obtain stress data that are necessary for wellbore stability modeling and for predicting and avoiding fracturing lost returns. Conventional leakoff tests are performed routinely to test the integrity of casing cement jobs, not to accurately measure earth stresses. The most important consideration was to develop methods that were easy to implement and would minimize disturbance to drilling operations, thereby promoting acceptance among operations personnel. The procedures are called Extended Leakoff Tests (XLOT).
Dome PDC Technology Enhances Slim-Hole Drilling and Underreaming in the Permian Basin
Authors: Carter J. A. , Akins M. E.
Published: December 2007

The Dome Polycrystalline Diamond Compact (PDC) is a relatively new development in PDC technology. The Dome PDC has a radius of curvature across the diamond table rather than being flat. Previous studies have shown the new design reduces torque and dissipates heat better than the conventional PDC.1 The dome design also offers a more impact resistant structure which in turn has potential for harder rock applications.

This paper addresses the application of the Dome PDC cutter in slim hole operations (3 1/4″ to 4 3/4″ diameters) in the Permian Basin. The new cutter has been tested and applied in dolomitic formations where conventional PDC’s have failed in the past. The 3/8″ diameter Dome PDC has been utilized on bits as well as underreamers. The use of Dome PDC bits has proven successful in the 3500′-4500′ Grayburg/San Andres formation of Lea County, New Mexico. The increased ROP’s and dependability of the fixed cutter in this area offer an economic advantage over roller cone technology. The Dome PDC bits have proven a fast economical way to deepen through 4″ and 5″ liners. The subsequent underreaming of wellbores with the Dome PDC in West Texas and New Mexico have shown savings in excess of 70% over roller cone tools. These savings are reflected by an increase of penetration rates from 10 FPH to over 30 FPH.

The performance of the Dome PDC in the Permian Basin greatly enhances opportunities for utilization of old producing wells for deepening and recompletions.
K-12 Technology and Engineering Education: Is it World Class?
Authors: Wright R. T.
Published: December 2007

Education in America varies from world class to ineffective. The challenge facing the nation is to move the less effective program to world class. This will require support from all members and institutions in society.

This paper deals with developing more effective technology and pre-engineering education for grades K-12 in American schools. To meet this challenge will take bold leadership to cause three major changes. First mathematics and science must abandon a focus on fact and skill mastery and move to activity-based conceptual learning. Second, meaningful technology education programs that use hands-on activities to study designing, producing, using and assessing technology must be available to all students at all grade levels. And finally, mathematics, science, and technology teachers must coordinate their teaching as they address their particular disciplines.
Early Performance and Planning for a Simultaneous Thermal Enhanced Oil Recovery Project and Sulfur Mining Operation at Main Pass 299
Authors: Lewis L. R. , Taylor B. P.
Published: December 2007

This paper will review the early production performance, development planning, and reservoir simulation prediction for a unique thermal enhanced oil recovery project and sulphur mining operation in a recently discovered reservoir at Main Pass 299. In this field, a relatively large accumulation of oil (approximately 100 million barrels in-place) is contained within a complex structure of sandstone, carbonate, and sulphur-bearing formations lying directly above a shallow piercement salt dome at depths ranging from 1200 to 1532 feet subsea. The sulphur-bearing formation has the largest sulphur reserves (67 million tons) of any mine in North America and is one of the largest mines in the world. As part of the sulphur mining operation, 240,000 barrels per day of 325 °F water will be injected into the formation. Much of this water will contact and heat up the oil, significantly reducing the oil viscosity and greatly enhancing the ultimate oil recovery. Main Pass 299 is located about 90 miles southeast of New Orleans in 220 feet of water (Figure 1).
CO2 Foam Field Trial at North Ward-Estes
Authors: Chou S. I. , Vasicek S. L. , Pisio D. L. , Jasek D. E. , Goodgame J. A.
Published: December 2007

A CO2 foam field trial was conducted in the North Ward-Estes field in Texas to evaluate the effectiveness of foam in improving CO2 sweep efficiency. This paper describes the design, results, and analysis of foam treatment with emphasis on the design methodology of applying foam in grossly heterogeneous reservoirs, characterized by uneven areal and vertical sweep in most patterns.

Over a period of nearly two years, foam was emplaced into an injector four times by alternately injecting CO2 and surfactant solution, and followed by continuous CO2 injection after each emplacement. Foam was generated in situ, which reduced CO2 injectivity by 40 to 85%. Gas production in the problem producer decreased dramatically, while gas and oil production in other offset producers increased, indicating areal diversion. Vertical diversion also occurred, as evidenced by significant increase in oil production in the problem producer, where tertiary oil response had peaked prior to the foam treatment.

The field test shows that a properly designed foam treatment can significantly improve the CO2 sweep efficiency and be economically successful. The methodology developed in the design and analysis of the foam test may be applied to other conformance improvement processes.
Integration of Horizontal Well Log Information in Fractured Reservoir Characterization
Authors: Meehan D. N. , Verma S. K.
Published: December 2007

Representation of reservoir heterogeneity for simulation models is one of the most challenging aspects of reservoir engineering. Naturally fractured reservoirs present an exceptionally difficult challenge in this respect. Vertical wells provide extremely limited information about the spatial distribution of fractures and fracture density as the hole size is small with respect to the characteristic spacing and distribution of natural fractures. Vertical wells fail to provide short scale (up to interwell distance) correlation information for geostatistical models in any type of reservoir. Outcrop representations of fracture distribution are generally inadequate and fail to correspond to in situ fracture characteristics. Formation evaluation in horizontal wells can provide both detailed information on fracture distribution and short-scale correlation information. This information can be integrated with geostatistical tools such as Sequential Indicator Simulation (SIS) models to provide much more realistic reservoir descriptions. These reservoir descriptions result in dramatically improved simulation matches. Further, this reservoir characterization technique can explain behavior that is far more difficult to explain with conventional and dual-porosity models.

This paper presents the following: A description of how horizontal well formation evaluation is used to obtain the spatial distribution in a naturally fractured reservoir,examples of variogram estimation with the derived data for both traditional and indicator variograms,examples from horizontal well performance used to develop additional correlation information,SIS models derived from the conditioning data from the horizontal wells and the indicator variograms, andreservoir simulation results for horizontal well performance.

This paper does not explain variograms, geostatistical models, correlation ranges, conditional simulation, etc.. However, the geostatistical software used was developed by the Stanford Center for Reservoir Forecasting1 and is available in Reference 1.
Laminated Clastic Reservoirs: The Interplay of Capillary Pressure and Sedimentary Architecture
Authors: Corbett P. W. M. , Ringrose P. S. , Jensen J. L. , Sorbie K. S.
Published: December 2007

Many scales of heterogeneity are present in clastic reservoirs. Important heterogeneities occur at the small-scale as a result of episodic or periodic fluctuations in the depositional process. These fluctuations are manifested as quasi-periodic grain size variations at scales of 10-3 to 1 metre. In the hierarchical description of sediments (the basis of sequence stratigraphy), these periodic stratal elements are known as laminae or beds.

The fluctuating grain size elements result in well determined variations in pore and pore-throat size distributions. The effects of pore throat distributions on two-phase flow are reflected in capillary pressure curves, which may differ strongly as a function of absolute permeability (especially for permeabilities less than 1 Darcy). When stratal elements of contrasting grain size, sorting and permeability occur in close proximity, significant differences in local capillary pressures may occur over short distances.

In common flow situations, these capillary pressure gradients can be comparable to or greater than pressure gradients induced by either viscous or gravitational effects. Such conditions occur when (a) permeability varies over very short distances (e.g., centimetres for the lamina scale), (b) flow rates are low (i.e., frontal advance rates are less than 1 metre/day), and (c) permeability contrasts are significant (i.e., of one order of magnitude or greater). These conditions occur in many laminated clastic reservoirs.

This paper shows how a knowledge of sedimentary architecture (stratal elements) can be exploited to scale-up these capillary effects. A multiphase flow upscaling methodology based firmly on the length scales represented within the hierarchy of stratal elements is presented. We refer to our approach as the geopseudo approach since it incorporates the flow/structure interactions at the lamina, bed and formation scales (i.e., it includes the geology in an appropriate manner).

The Rannoch Formation of the Brent Group (North Sea) provides an interesting practical example where large scale production performance is seen to be affected by the interaction of capillary forces with small-scale structure.
Auger Field Subsurface Overview: Future Site of World-Record Deepwater Tension Leg Platform
Authors: Bilinski P. W. , Crabtree P. T. , Crump J. G. , McGee D. T. , Watson R. C.
Published: December 2007

This paper provides an overview of the Auger field, currently predrilling wells for the future site of a world-record water depth Tension Leg Platform (TLP). Major areas covered will be: *Descriptions of the subsurface data including the results of the first seven predrill wells,*A brief discussion of the excellent drilling, safety, and environmental performance exhibited by the predrill rig, and*A general field overview, including the volumetrics and current development strategies.
Novel Well Testing Applications of Laplace Transform Deconvolution
Authors: Fair P. S. , Simmons J. F.
Published: December 2007

Well-test solutions are formulated typically as a dimensionless pressure change that occurs in response to a single change in flow rate. Ideally, the rate change is a step change in sandface flow rate; however, in practice wellbore storage and poor control of surface flow rate often lead to variable-rate tests. Deconvolution methods have been shown to improve analysis of such data by removing the effects of undesired rate variations from the measured pressure response.

In 1988, Roumboutsos and Stewart1 proposed deconvolving well-test data by numerically transforming the discrete pressure and rate data into the Laplace transform domain. In Laplace space, the often difficult deconvolution process is reduced to simple division. Roumboutsos and Stewart also introduced a method of synthetically deconvolving constant wellbore-storage pressure data without explicitly measuring the flow rate.

This paper extends the concepts introduced by Roumboutsos and Stewart and demonstrates that when the wellbore storage is constant, a trial and error method may be used to estimate storage and progressively strip away the afterflow effects. Moreover, when storage is not constant, a series of synthetic deconvolutions may be used to strip away the constant components of storage to reveal the variable components of the total wellbore storage.

A new concept of afterflow extraction is introduced. In this technique, an analytic reservoir solution is substituted in the Laplace domain and used to explicitly calculate afterflow. This technique can be used to evaluate flow meter performance.

Afterflow extraction provides a unique opportunity to investigate the sensitivity of deconvolution to errors in flow rate measurement. Examples are presented in which afterflow is extracted from a single set of pressure data using multiple reservoir solutions (i.e., radial, dualporosity, etc.). Each of the extracted afterflow profiles are then used to deconvolve the recorded pressure data. The examples illustrate that extremely slight differences in the afterflow can significantly alter the deconvolved response. These examples show how small errors in afterflow measurement can result in an incorrect diagnosis of the reservoir model.
A New Technique to Estimate Vertical Variability of Rock Properties for Reservoir Rock Evaluation
Authors: Sharma Bijon
Published: December 2007

A new technique is presented for a more effective description of the vertical variability of reservoir rock properties that are typically obtained or derived from wireline logs or determined from laboratory measurements of core samples.

Rock properties and other data available for this study were the geological description of cores, XRD analysis of core samples for mineral percentages, SEM and CT-scan data from a few selected wells in two fields, namely Patrick Draw (WY) and Bell Creek (MT), laboratory measured porosity, air permeability, and primary and waterflood oil production data from the wells studied.

In this investigation, first the vertical distribution of reservoir rock properties available as a function of depth is transformed into functions of frequency (cycles per foot) by the application of standard time series analysis techniques. A statistical parameter called the ‘power spectrum’ is calculated which gives the variance of the time series for each frequency. In this way a continuous description of variances is obtained for each frequency into which the original series has been transformed.

Estimation of vertical variability of rock properties was initiated by computation of ‘power spectra’ of core measured permeability, and digitized gamma ray, sonic, density and neutron logs. The power decay patterns with frequency were correlated with reservoir rock properties and oil production, and it was observed that different logs had different decay patterns in sandstones having different distributions of reservoir properties. The power spectra of permeability, sonic, and gamma ray logs for a clean sandstone or for a sandstone with uniform properties (low variance) decayed very rapidly at higher frequencies if there was no thin bed stratification and assumed very low powers at the high frequency end. The sandstone with variable reservoir properties had power spectra that decayed more gently, and the slope of spectral decay was a measure of the vertical distribution of reservoir properties, in the sandstone. For a few wells, the spectra of density logs in kaolinite clay filled sandstones showed very low amplitudes at higher frequencies because the matrix rocks (predominantly quartz) and the clays (dominantly kaolinites) both had nearly the same density (around 2.64 g/cm3).

From minimal geological information, studies of highly automated spectral decay curves of different types of distributions could provide quantitative information on vertical variability of reservoir rock properties in different parts of a field. Under favorable conditions the study of decay spectra of a combination of logs may provide quantitative information on the variations in cement content and the types and volumes of clays in reservoir rocks.
An Integrated Subsurface Study Directed at Optimizing Turbidite Sand Completion Strategies
Authors: Scheibal J. R. , Weiland J. L. , Worrel J. M.
Published: December 2007

An integrated subsurface engineering study was undertaken to examine ways to optimize high cost, technically-difficult P1iocene/P1eistocene turbidite developments in the Gulf of Mexico. This study utilized a multidisciplinary approach in which both open and cased hole data was applied to quantifying and qualifying downhole flow performance in different turbidite facies.

Data from Produce While Drilling (PWD) operations and Pressure Volume Temperature (PVT) tests proved to be extremely valuable when combined with base wireline logs in delineating the production characteristics through time.
Completion Design for Deep, Sour Norphlet Gas Wells Offshore Mobile, Alabama
Authors: McDermott J. R. , Martin B. L.
Published: December 2007

Producing gas from the Norphlet formation in the Mobile Bay Area presents many unique completion design challenges. The Mobile Bay Area Norphlet, a consolidated aeolian sandstone, is estimated to contain an ultimate natural gas resource base of 20 TCF1. Proved reserves of 4 - 6 TCF have been discovered to date with hydrogen sulfide concentrations ranging from 50 ppm to 10% and carbon dioxide concentrations up to 4%. Production may also include brine and elemental sulfur. Formation intervals below 20,000′ have bottomhole temperatures in excess of 400°F and initial bottomhole pressures from 10,000 psi to 20,000 psi2. Wells can cost upwards of thirty million dollars to drill and complete due to the extreme depth, the highly corrosive nature of the gas, and the close proximity to environmentally sensitive areas. Economics dictate development with a minimum number of wells on wide spacing, therefore, completions are designed for maximum rate and maximum life.

This paper describes the evolution of design concepts and equipment innovations utilized in the completion of Norphlet gas wells in the Lower Mobile Bay - Mary Ann and Mobile 823 Fields.
Two-Phase Flow Metering by Pressure Pulse Propagation
Authors: Gudmundsson J.-S. , Dong L. , Rødøy F.
Published: December 2007

The propagation velocity of a pressure pulse through a gas/liquid mixture flowing in a pipeline can be used for metering purposes. The pressure pulse propagation method is presented and a theoretical model developed for the propagation velocity of pressure pulses through gas/liquid mixtures. Preliminary experimental work on pressure pulse propagation measurements in air/water horizontal slug flow are reported. For these flow conditions, the velocity of a gas/liquid mixture can be obtained directly from time-of-flight measurements to upstream and down-stream stations when the void fraction is in the range 10–85 percent.
An Expert System for Matrix Acidizing Treatment Design
Authors: Van Domelen M. S. , Ford W. G. F. , Chiu T. J.
Published: December 2007

This paper describes the development of a PC-based Matrix Acidizing Expert System (Acid Expert) with emphasis on the knowledge acquisition process and the knowledge bases. This system is currently being used to design damage removal treatments for sandstone formations. The primary objectives of the system are (1) to provide acidizing treatment designs based upon an accumulation of knowledge from experts, (2) to provide technical information and guidelines on the proper use of additives and (3) to serve as a training tool to assimilate company expertise for less experienced personnel.

Application of this expert system to treatment design is illustrated using a documented case history. The subject case history deals with a sandstone reservoir for which significant changes in the treatment procedures were recommended and implemented based upon the knowledge base built into Acid Expert.
Coiled Tubing in High-Pressure Wells
Authors: Newman K. R. , Allcorn M. G.
Published: December 2007

The number and types of well services that are performed using coiled tubing (CT) are increasing rapidly. These services have typically been limited to wells with well-head pressures (WHP) below 3,500psi. CT can be used safely in wells with higher WHP. The special considerations involved in the job design for wells with higher WHPs are reviewed in this paper. These special considerations include: Well control equipment capable of operating safely with high WHPBurst and collapse limits of the CTInjector head capable of pushing the CT into the well against the WHPThe possibility of buckling of the CT between the chains and the stripper
A Component Performance Evaluation of Constructed Surface Flow and Wetlands Cells for Produced Water Treatment in the Pitchfork Field, Wyoming
Authors: Caswell P. C. , Gelb Dan , Marinello S. A. , Emerick J. C. , Cohen R. R.
Published: December 2007

The quality of produced water discharge is of increasing concern as the quality of potable waters in western states becomes a critical issue. The impact of discharged waters on the downstream water quality, as well as the flora and fauna within the discharge zone, is dependent on the quality of the water ultimately released into the drainage basin from the field. West of the 98th meridian, where surface discharge of produced water is permitted through the NPDES program, many permits are being re-evaluated and in some cased recalled due to actual and/or perceived impacts on the surface and ground water. In Wyoming, the quality of the water is of even further concern because of its potential use by farmers and ranchers.

This paper evaluates a water treatment system that consists of four surface flow cells and a wetland unit. To develop effective design criteria and to isolate the various treatment mechanisms, the system components were independently analyzed.

The system has been operational since May of 1991 with periodic sampling and testing. Initial results are very encouraging. The system appeared to handle the winter stress by a shift in active processes and locations. Mechanical, chemical, and biological treatment in the surface flow cells and wetlands unit have significantly reduced the existing sulfide problem, as well as having reduced the released radium concentration.
MRI Studies of Permeability Control Using Biopolymers
Authors: Barrufet M. A. , Perez J. M. , Mondava S. S. , Ali Liagat , Poston S. W.
Published: December 2007

Severe changes in rock permeability among adjacent oil bearing horizons presents an enhanced oil recovery problem. Fluids used to displace indigenous oil tend to follow the high permeability avenues, bypassing large reserves of oil.

The use of a modified biopolymer, starch, as a method to enhance oil recovery was evaluated by analyzing: 1) changes in rock permeability caused by the macromolecular gel matrix of the polymer solution, 2) mobility reduction due to the higher viscosity of the polymer solution compared to that of water, 3) the chemical and mechanical stability of the biopolymer at reservoir conditions, 4) the effect of various polymer injection strategies, and 5) sweep efficiencies by Nuclear Magnetic Resonance Imaging (NMR/MRI).

Artificially as well naturally consolidated porous media with initial permeabilities ranging from 1,500 to 2,500 md were used. The average permeability reduction was from 1,500 to 500 md when a 1% by weight biopolymer was used. NMR/MRI proved to be a very useful tool to evaluate the effectiveness of a starch biopolymer for rock permeability control. Vertical sweep efficiencies measured by NMR means improved from 25% to 95% with the introduction of the biopolymer. Oil recovery was dramatically enhanced from 2% of the Original Oil in Place (OOIP) using brine as driving fluid to 98% when the in-house biopolymer was used during the displacement tests. Differential pressure (Δp) across 3-inch long samples constantly increased from 10 to 130 psi. A xanthan-gum based commercial biopolymer yielded a recovery of only 58% of the OOIP when used under similar conditions. Displacement experiments were conducted at 1,000 psi and 160°F. The polymer solution exhibited moderate shear thinning viscoelastic behavior and pronounced shear thickening viscosity with increasing brine and polymer concentration.
Flow Of A Disperse Emulsion Of Crude Oil In Water In Porous Media
Authors: Cartmill John C. , Dickey Parke A.
Published: December 2007

It has been suggested that oil migrates through reservoir sands in the form of a fine, disperse emulsion of oil in water, and that oil accumulations occur where the stream enters finer-grained rock such as silt or shale. In order to investigate the possible mechanisms, stable emulsions of oil in water were prepared without the use of wetting agents. They consisted of droplets 1/2 to 1-1/2 microns in diameter, in a concentration of 20 to 40 parts of oil per million of water. These emulsions passed freely through filter paper and ordinary passed freely through filter paper and ordinary sand. A plastic tube containing glass beads of 200-microns diameter included a bed 1/2-cm thick of crushed beads 37 to 88 microns in diameter. When the emulsion was passed through this tube, up to 80 percent of the oil was screened out at the coarse-fine interface. The amount removed depended on the contrast in grain size, the nature and the preferential wettability of the media. Similar results occurred when quartz sand was used as the coarse, and crushed sand as the fine medium. This screening did not occur as a result of capillary effects., because the pores were many times the diameter of the droplets. The oil collected as a result of flocculation of the droplets into strings and clusters., and the oil saturation in the pores consisted of masses of droplets with very little coalescence. Possibly electrostatic forces are more important Possibly electrostatic forces are more important than capillary in the behavior of fine, disperse, oil-in-water emulsions. our current ideas on multiphase flow in porous media may not apply to disperse emulsions.

Introduction

The physical mechanisms of the migration of oil, including the expulsion of oil from the source rock, its migration, and its accumulation in the reservoir rock, are very poorly understood. Most authorities believe that the expulsion of water from compacting shale causes regional flows of water within the pores of the enclosing sediments, and the water somehow carries the oil with it. Hydrocarbons heavier than decane have such a low solubility in water that it is inconceivable that large quantities could have migrated as true solutions. Most subsurface waters have near normal oil-water interfacial tension, so that migration in "solubilized" form as suggested by Baker is improbable. Conventional reservoir mechanics require that oil occupy more than 15 percent of the pore volume in order to exist as a continuous, mobile component. No doubt migration in the continuous phase has occurred frequently, especially secondarily when previously formed oil accumulations have been shifted by tilting of the reservoir rocks. However, such movements should leave residual oil saturations and staining in the flow paths.
Characterization of Pore Structures Using NMR-Restricted Diffusion Measurements
Authors: Chen Songhua , Miao Peizhi , Watson A. T.
Published: December 2007

The self-diffusional motion of fluid molecules in a porous medium is expected to be different from that in the bulk fluid due to the presence of pore boundaries which restrict the molecules diffusing within the pore space. Thus it is conceivable that the study of restricted diffusion may provide information leading to pore structure characterization. We report the use of pulsed field gradient nuclear magnetic resonance (PFG NMR) techniques to study proton restricted self-diffusion in porous media. Measurements were conducted in model porous media consisting of different sized glass bead packs, as well as porous rocks. Computational analyses were carried out to obtain apparent diffusivities and other characteristics from the experimental results.
Dynamic Capillary Pressure Curve for Water/Oil Displacement in Porous Media: Theory vs. Experiment
Authors: Kalaydjian F. J- M.
Published: December 2007

The dependence of the capillary pressure on the flow rate, for two-phase flow in porous media, has been theoretically and experimentally investigated.

A theoretical dynamic expression for the capillary pressure has been derived which involves a dynamic term which is proportional to the time derivative of the saturation. A series of waterfloods have been performed at different flow rates. While flowing the cores, capillary pressure and saturations have been locally measured. Capillary pressure has been found to depend on the flow rate as theoretically predicted: it increases with the flow rate and its derivative with respect to saturation mostly decreases when the flow rate is increased.

The dynamic term is interpreted as the contribution of the viscous forces to the pressure drops. A strong impact of this dynamic expression on two-phase flow modelling and calculation of relative permeabilities has been found.
Laboratory Testing of a Microbial Enhanced Oil Recovery Process Under Anaerobic Conditions
Authors: Rouse Bruce , Hiebert Franz , Lake L. W.
Published: December 2007

Microbial enhanced oil recovery (MEOR) is a potentially attractive way to recover additional or incremental oil from a reservoir beyond conventional operations. The objective of this work was to determine the effectiveness of a commercial MEOR iystem in controlled laboratory corefloods. The experiments were carried out as support for a field test conducted in the Shannon Formation of the Teapot Dome reservoir.

Two sets of coreflood experiments were designed in order to carry out this research. The first set was designed to determine the incremental oil production of each of the components of the MEOR system, both individually and in all possible combinations. The second set of experiments attempted to maximize the opportunity for incremental oil production to occur. The results indicate that, under the conditions tested, there was no incremental increase in oil recovery as a result of the MEOR system.
Mixed Culture Microbial Enhanced Waterflood: Tertiary MEOR Case Study
Authors: Portwood J. T. , Hiebert F. K.
Published: December 2007

Microbial enhanced oil recovery (MEOR) is rapidly developing as a technology, and case studies from field applications are essential to its growth. This paper will discuss a small waterflooded reservoir which was inoculated with a commercial MEOR process in order to cost-effectively increase oil production.

Treatment goal was to design and implement MEOR in an existing waterflood so that metabolic byproducts of the bacteria produced in reservoir pores, would cause the release of previously immobile oil. The oil release mechanism is similar to chemical solvent and surfactant flooding. Water injection volumes, oil and water production volumes, and hydrocarbon-degrading bacteria (HDB) populations are presented before and after MEOR treatment.
Factors Affecting the Stability of Proppant in Propped Fractures: Results of a Laboratory Study
Authors: Milton-Tayler David , Stephenson Chris , Asgian M. I.
Published: December 2007

Factors controlling the stability of proppant in propped fractures were identified and investigated experimentally. The results indicate that the absolute size, distribution and type of proppant may affect stability, and hence the likelihood of proppant flowback.

The extent of aTbedment of the proppant into the rock (determined by closure stress and rock hardness) was found to play a key role in stabilising the pack. In addition, channels, which may form due to proppant settling before fracture closure, were found to significantly reduce stability. These are, therefore, favourable sites for proppant flowback.

A numerical study has been used to determine lengths of unpropped fractures which may be maintained open due to the rock stiffness. The implications of these results for well productivity and the understood mechanisms of proppant flowback, in the field, are discussed.
Fracturing Pressures for Horizontal Wells
Authors: Owens K. A. , Andersen S. A. , Economides M. J.
Published: December 2007

A fully horizontal well, drilled at an angle from the fracture plane, will experience a potentially substantial increase in the fracturing pressure. The magnitude of this pressure depends on the angle (as the angle increases so does the pressure) and, very importantly, on the value of the intermediate of the three far-field stresses.

Application of these findings to eight horizontal wells in the DAN field and comparison with actual data from several fracture treatments within each well showed an excellent match between predicted and observed fracturing pressures. The results are presented in this paper.
Determination of Fracture Geometry Using Field Data Coupled With a Fracture Simulator
Authors: Martinez A. D. , Pardo C. W. , Ellis P. D. , Pittman R. W.
Published: December 2007

A practical analysis technique for the determination of fracture geometry using actual treatment signals has been developed using a commercial 3D fracture simulator. This simulator allows the use of treatment data as well as reservoir and fluid properties to be incorporated into the determination of fracture geometry. This analysis has been applied to typical, water-based fluid treatments using readily available surface treatment data. Although the simulator has the option to incorporate energized and foam fluids, we have not yet used it to analyze these type jobs due to the lack of treatment bottom hole pressures and temperatures.

The analysis technique has been applied to several treatments in various parts of the United States. The process involves taking treatment data (injection rate, proppant concentration, etc.) and obtaining a history match of the surface treating pressure. Several practical analysis techniques are employed to enhance the confidence in the resulting fracture geometry. In the case where mini-fracture data is available, the mini-fracture treating and falloff pressure responses are matched with the simulator to determine the corresponding reservoir parameters. Using the mini-fracture defined parameters, the main treatment is analyzed and history matched. Based on the resultant fracture geometry obtained from the simulator, future treatment designs can be altered or refined to obtain the optimum fracture geometry for the reservoir.
Hydraulic Fracturing Research in the Frontier Formation Through the Gas Research Institute’s Fourth Staged Field Experiment
Authors: Saunders B. F. , Robinson B. M. , Holditch S. A. , Holditch S. A. , Peterson R. E.
Published: December 2007

The Gas Research Institute (GRI) has sponsored a field based research program through the Staged Field Experiment (SFE) project for the last several years. SFE wells are drilled specifically for conducting research in the analysis and stimulation of tight sands and for validating technologies under development in other GRI projects. The majority of this work was spent in the Travis Peak and Cotton Valley formations in east Texas where the first three SFE wells were drilled. Results of this work have already been published in GRI reports1–3 and SPE papers4–6. This paper summarizes the results from research conducted on the fourth SFE well. This well was drilled in the Frontier formation of southwestern Wyoming. A primary objective of this SFE was to determine if technology developed in previous SFE wells in east Texas can be successfully transferred to ther geologic basins.

In order to fully describe each of the layers of rock on SFE wells, data are collected from whole cores, openhole geophysical logs, in-situ stress measurements, production and pressure transient tests, fracture injection treatments, and fracture diagnostic measurements. These data are then analyzed in detail with advanced formation evaluation techniques, including numerical models, in an effort to obtain the best possible description of the reservoir and hydraulic fracture. On SFE No. 4, there were several new technologies and analysis methods that were being evaluated. Specifically, these techniques to evaluate SFE No. 4 included in-situ stress profiling, fracture height and azimuth analysis, hydraulic fracture analysis, and post-fracture performance analysis.

Knowledge and techniques developed through GRI research programs are designed to benefit the natural gas industry. A better understanding and more accurate analysis of the hydraulic fracturing process will lead to improved treatment designs and additional gas production from tight sands such as the Frontier. A goal of the GRI program is to apply rigorous analysis techniques to evaluate hydraulic fracture treatments in any geologic basin. The SFE No. 4 in southwestern Wyoming illustrates that rigorous analysis techniques can be used to analyze and better understand fracture geometries in complex reservoirs that typify tight gas formations.
Small, Highly Conductive Fractures Near Reservoir Fluid Contacts: Application to Prudhoe Bay
Authors: Martins P. J. , Collins P. J. , Rylance Martin , Ibe O. E. , Kelly R. T. , Bartel P. A.
Published: December 2007

The paper describes the techniques used in Prudhoe Bay to place small, highly conductive fractures in areas of the field where there is no fracture containment to prevent fracture growth into an aquifer.

A reservoir study to investigate the effects of fracturing close to oil water contacts is presented, together with 3D fracture modelling of fractures with no downward containment. The paper highlights the importance of spurt losses in both frac designs and minifrac analyses, when fracturing high permeability reservoirs. A simple minifrac analysis, for use with complex fracture geometries, is provided.

The fracture design methodology is presented, supported by field examples.
Reservoir Evaluation, Completion Techniques, and Recent Results From Barnett Shale Development in the Fort Worth Basin
Authors: Lancaster D. E. , McKetta S. F. , Hill R. E. , Guidry F. K. , Jochen J. E.
Published: December 2007

This paper describes the evaluation, completion, stimulation, and testing of Barnett Shale wells operated by Mitchell Energy Corporation (MEC) in the Fort Worth Basin of north-central Texas. In particular, the paper presents a detailed analysis of data collected from a Gas Research Institute/MEC cooperative research well that was used to gain a better understanding of the mechanisms controlling gas production from the Barnett Shale. The Barnett Shale covers a large geographic area of north-central Texas; thus far, most of the activity is centered around Wise and Denton Counties, TX.

On the basis of the data analyzed, the Barnett Shale appears to be characterized best with a layered reservoir description where most of the well deliverability is associated with thin, higher permeability, naturally fractured zones, while most of the gas-in-place is confined to thicker, extremely low permeability layers. Gas-in-place in the Barnett Shale may average 10 to 12 Bscf per 160 acres, but the better wells are expected to recover only 1 to 1.5 Bscf in a twenty-year well life. Approximately 20% of the gas-in-place in the Barnett Shale is adsorbed gas; however, desorption appears to become important only after the reservoir pressure falls below 1,000 psia (original reservoir pressure is about 4,000 psia). Evaluation of fracturing pressures and post-fracture well tests suggests long, propped hydraulic fractures are being achieved and that the hydraulic fractures are typically contained within the Barnett Shale by limestone formations above and below.
From Stochastic Geological Description to Production Forecasting in Heterogeneous Layered Reservoirs
Authors: Hove Kjetil , Olsen Gudmund , Nilsson Stefan , Tønnesen Morten , Hatløy Andres
Published: December 2007

This paper discusses the data transfer from a detailed gridded stochastic geological model to a more coarsely gridded reservoir simulation model. A new gridding technique has been developed to follow the main geological features. This technique makes the transformation between the geological model and the reservoir model more accurate and efficient. It has been successfully applied in field evaluations for a North Sea sandstone reservoir.

The reservoir in question is very heterogeneous. Conventional geological models based on smooth parameter interpolation between well data do not reflect these heterogeneities. A two-stage stochastic geological model was therefore used to represent the reservoir.

In the first stage the geological architecture of the reservoir was constructed. In the second stage petrophysical values were assigned to each building block in the geological model. This two-stage modelling procedure was described by Damsleth et. al.1.

The complete study is reported, from the stochastic geological model via the new gridding procedure and homogenization to simulated production forecasts. The effects of different assumptions in the gridding have been evaluated using both water, gas and WAG injection as well as depletion. A procedure for incorporating the results into the total field production forecast is outlined.

The importance of representing the main geological features in the gridding is demonstrated. When a regular coarse grid was used, the contrasts in reservoir properties were smoothed out by averaging, and in most cases a more optimistic production performance was then predicted.

Detailed stochastic geological models can give more realistic production profiles for the reservoir. In this study the stochastic model resulted in a reduction in recovery compared to conventional models.