bluuebunny/crossref_metadata_2025 huggingface dataset:
Paraffin Crystal and Deposition Control By Emulsification
Authors: Ahn S. , Wang K. S. , Shuler P. J. , Creek J. L. , Tang Y.
Published: December 2007

This laboratory investigation considers the effects of emulsions (via adding surfactants) and the formation and deposition of paraffin wax. This study relates the properties of added surfactant and emulsion characteristics with their wax deposition tendency. Parameters considered include the surfactant HLB (Hydrophilic Lipophilic Balance), molecular weight, and surfactant concentration. Two different series of commercial nonionic surfactants are included in this study; Triton-X (ethoxylated phenols) and Tween (sorbitan) products. The hydrocarbon phase is a model oil; a mixture of paraffin's with carbon numbers from C21 to C48 dissolved in n-decane (C10). Emulsion characterization was done by IFT (interfacial tension), viscosity measurement, and optical microscopy. The wax deposition measurements were performed in a novel cell apparatus where stirring controls the hydrodynamics and mixing energy.

The study results indicate adding surfactants to promote emulsification can reduce the tendency for wax deposition. Properties that induce tighter emulsions such as lower interfacial tension and greater shear rate lead to reduced paraffin deposition. Furthermore, the wax that does deposit from an emulsion is softer (lower average molecular weight) versus wax that deposits in the absence of any chemical. In contrast, the wax that deposits in the presence of some commercial polymer-based wax inhibitors can be even harder (higher average molecular weight) than the deposit formed in the absence of any chemical additive.
Improved Accuracy of Modeling for Optimization of Squeeze Design
Authors: Mackay E. J. , Al-Mandhari S. , Peacock J. , Hammond B.
Published: December 2007

Scale inhibitors may be injected periodically into production wells to prevent loss of productivity due to scale deposition. These squeeze treatments are routinely modelled and optimised using near-wellbore simulators. Typically these calculations assume that inhibitor distribution along the wellbore is controlled by the permeability length product, kh, (measured in mD.ft or mD.m). However, most reservoir engineering calculations performed using a reservoir simulator assume that production profiles may also be controlled by a variety of other parameters, such as wellbore friction (in horizontal wells), interval pressures (in reservoirs with non-communicating layers), well orientation, etc.

This paper describes the comparison of squeeze life calculated using a simple near-well simulator where inhibitor injection profiles assume that placement is controlled entirely by the kh factors, with calculations which are also performed using a near-well simulator, but in which reservoir simulation data is used to account for the influence of other parameters. In this study, 26 wells from one field were studied. For the majority it was demonstrated that assuming the injection profile would follow the kh profile was quite adequate. However, in five wells inhibitor placement was shown to be dominated by factors other than the kh product, and thus squeeze modelling that takes account of these other factors (wellbore friction and crossflow) would render significantly more accurate predictions of squeeze performance.

Knowledge of injection and production profiles derived from the field model was then used to optimise the design of squeeze treatments in two wells. The objective here was not only to maintain/extend squeeze life, but also to reduce the period during which process upsets were occurring post squeeze due to high concentrations of inhibitor causing emulsion bands and reducing separator efficiency. Previously published simulation work had demonstrated that by increasing the overflush volume, the concentration at which inhibitor would flow back in the first few hours of production would be reduced. This was validated by field results. However, in some cases the reduction in concentration was not sufficient (<1,000 ppm), and in fact the period during which process upsets were occurring increased. This was because in these cases, although the height of the concentration spike was reduced, it was not reduced sufficiently, and in the process the spike was broadened. Calculations were therefore performed to evaluate how much further the overflush would have to be increased to reduce the height of the spike below the level at which it was considered process upsets would not occur. The benefit of this was then evaluated relative to any increase in squeeze life on the one hand, and issues related to lifting the injected water and the well downtime with resulting deferred oil on the other hand.
Phase Redistribution and Horizontal Well Effects on Black-Oil Model of a Rich Gas Condensate Reservoir
Authors: Izgec B. , Barrufet M. A.
Published: December 2007

The black-oil model (MBO) of a gas condensate reservoir was tested against the fully compositional model and performances of both models were compared using various production and injection scenarios.

We evaluated the performance of MBO model by investigating: the effects of black-oil PVT table generation methods from a tuned equation-of-state, oil-gas ratio (OGR) and saturation pressure versus depth as initialization methods, uniform composition versus compositional gradient with depth, location of the completions, production and injection rates, kv/kh ratios, and vertical wells versus horizontal wells.

Contrary to the common belief that OGR versus depth initialization gives better representation of original fluids in place, initializations with saturation pressure versus depth gave closer original fluids in place considering the true initial fluids in place are given by the fully compositional model initialized with compositional gradient.

Unrealistic vaporization in the MBO model was encountered in both, production by natural depletion, gas cycling and as well as during the shut-in period of the producer. The changes in oil-gas ratio of the recyled gas showed that, it is not possible to accurately represent the changing PVT properties of the recycled gas with a single PVT table. Unrealistic vaporization also led to different arrival times for the displacement fronts and different saturation profiles for the near wellbore area and for the entire reservoir for the two models even though the production performance of the models was in good agreement.

The MBO model representation of compositional phenomena for a gas condensate reservoir proved to be adequate for full pressure maintenance, reduced vertical communication, vertical well with upper completions, and for horizontal well producers.
Possible Mechanism of the Drag Reduction Phenomenon in Light of the Associated Heat Transfer Reduction
Authors: Hamouda A. A. , Evensen F. S.
Published: December 2007

Drag reduction phenomenon has been known for more than 55 years. The mechanism by which friction reduction occurs has been a subject of intense discussion since its discovery in 1947. It has been reported previously the mutual influence of the polymer drag reducers (DRA) and the paraffin deposition in pipelines. In order to understand this effect, as a first step, a study of the heat transfer in presence of DRA is addressed in this paper.

Onset wall shear stresses (critical shear stress-tw*) are determined for two heat transfer conditions (40/32 and 40/28°C) of a crude oil/water heat exchanger system in presence of two types of oil soluble DRA (having the same chemistry but the average molecular weight of DRA1 is about 5 times higher than that for DRA2). The onset wall shear stresses are about 7.9 and 9.0 N/m2 for the first and second heat transfer conditions, respectively. Both polymer solutions showed same values at the corresponding heat transfer conditions.

The paper discusses the effect of the DRA polymers on heat transfer and suggests possible mechanism for the drag reduction in pipeline. It also suggests explanation on some of the observation in literature in laboratory compared to the field data.
Downhole Scale Formation and Inhibition in Mild Sulphate Scaling Conditions
Authors: Stalker R. , Graham G. M. , Hellings G. , Williams Joanne C. , Littlehales I.
Published: December 2007

Proposal

The presence of a mild scaling regime in a field necessitates effective measures to be taken to prevent scale formation before production is adversely impacted. However, in many cases the scaling regimes are too mild to be investigated by conventional laboratory inhibitor test protocols under realistic timescales. In such cases, laboratory testing of inhibitor chemicals can often be achieved by conventional methods only by artificially increasing the severity of the scaling regime, and thus potentially underestimating the field performance of the inhibitor. A novel dynamic core blocking test procedure which allows laboratory evaluation of inhibitor performance in such mild scaling regimes within realistic timescales has been developed and applied to a field-specific case. In this paper, we report the further development of this test method. We describe a field example in which inhibitor performance and inhibitory mechanism have been examined using this method, allowing scale squeeze treatments to be recommended at lower percent sea water breakthrough of ~ 30 % rather than the originally planned level of ~ 50%.
Use of Low-Dosage Hydrate Inhibitors in Sour Systems
Authors: Thieu V. , Frostman L. M.
Published: December 2007

Low-dosage hydrate inhibitors (LDHIs) continue to gain acceptance as alternatives to traditional hydrate control techniques. While these products have been in use for numerous years, there have been few reports of the use of LDHIs in sour systems. Hydrogen sulfide (H2S) has long been known to affect the conditions at which hydrates become stable. Often, the presence of percent levels of H2S significantly increases the temperature at which hydrates can form in hydrocarbon production and transmission systems compared to the corresponding sweet system. Many questions have been raised as to whether the presence of H2S affects the performance of LDHIs. While LDHI performance tests in sweet systems have become routine, it is very difficult to test LDHI performance in the presence of significant H2 S. Despite the difficulties in studying LDHIs in sour systems in the laboratory or pilot scale tests, several field applications of LDHIs have been conducted over the last several years. This paper will detail five case histories of successful field applications of both kinetic hydrate inhibitors (KHIs) and anti-agglomerants (AAs) in sour systems. The results show that LDHIs can indeed be used effectively to control hydrates in sour systems.
Screening and Selection of Alternative Hydrate Inhibitors Using a Model Apparatus Under Dynamic Conditions
Authors: Jonap K. , Vass A. , Vago A.
Published: December 2007

The gas industry (production, preparation, transportation) prevention of hydrate formation in pipelines using thermodynamic inhibitors (such as methanol) still represent a crucial problem from both technical and environmental points of view. Peculiar demand of the gas industry is represented by the fact that stability of gas flow and transportation must be extended towards lower temperature and higher-pressure range, which needs revised theoretical and practical approaches. Therefore, application of new innovative technologies and development of low-dosage chemicals, such as kinetic or anti-agglomerates inhibitors, are more than timely even today. The new and efficient compounds may retard hydrate formation for longer time than the residence time of the gas within the hydrate-prone section of pipelines and the low dosage inhibitors can also offer significant economic and environmental advantages compared to the traditional thermodynamic inhibitor.

To facilitate fast screening and selection of brand new inhibitors a model apparatus operating under dynamic conditions was developed. The sophisticated technique made the digital visualization and precise flow measurements possible at LT-HP conditions. The physical model system was fully computerized, all parameters were measured, processed and archived simultaneously.
Acrolein Application to Mitigate Biogenic Sulfides and Remediate Injection Well Damage in a Gas Plant Water Disposal System
Authors: Reed C. , Foshee J. , Penkala J. E. , Roberson M.
Published: December 2007

The unique and reactive chemistry of acrolein enables a 3-fold approach to oilfield problems stemming from sulfate reducing bacteria (SRB): 1) it is an effective biocide, 2) it scavenges H2S, and 3) it dissolves iron sulfide.

In this study, the utility of acrolein for remediation of problems with SRB and biogenic sulfides in a gas plant water disposal system at an Exxon Mobil facility in Mobile Bay, Alabama is presented. The disposal system, designed to handle produced water from offshore, process water from gas plant operations, and surface water drainage within the plant, was losing capacity due to iron sulfide fouling of the surface equipment and plugging of the disposal wells.

Bacterial monitoring indicated that SRB originating from the drain water had become established in the tanks and flowlines. These SRB were generating 8-10 ppm dissolved H2S that was ultimately responsible for the iron sulfide formation. The iron sulfide resulted in poor water quality (Millipore® rates=200-300 ml/5 min), tank fouling, filter plugging, injection line scaling, and loss of injectivity due to near well bore damage in the disposal wells.

The treatment design consisted of 1) initial remediation of injection wells by acrolein squeeze stimulations using a coiled tubing unit, 2) removal of iron sulfide pads from the tankage and iron sulfide build up in the disposal lines, and mitigation of SRB populations via batch treatments with acrolein, and 3) preventive maintenance using a continuous and batch treatment program with acrolein.

Immediately following squeeze treatment of the disposal wells, a 30% increase in capacity was observed. The topside treatment program has resulted in a 400 to 500% improvement in Millipore® rates, decreased levels of SRB, greater than 90% decrease in soluble H2S and a 65% decrease in filter replacements. Overall benefits of the program include acceptable injection rates and pressures and reduced operating costs through decreased filter changes, remedial expenses to maintain the disposal wells, and water trucking expenses.
Challenges and Insights in Optimizing Oil Production from Middle East Mega Karst Reservoirs
Authors: Trice R.
Published: December 2007

This paper is a summary of ongoing work to establish the impact of karst on optimizing oil production from carbonate reservoirs. The paper is based on a review of 44 Middle East carbonate reservoirs and is intended to convey preliminary findings. Key observations from this review are that karst reservoirs in the Middle East form one end-member of a continuum that includes, a) conventional layered reservoirs, b) fractured reservoirs, and c) karst reservoirs. It is also evident that many Middle East reservoirs are hybrid reservoirs having static and dynamic characteristics of all three end-members. In such instances the key challenge is to differentiate any karst components that may impact on achieving optimum oil production. Attempting to differentiate the karst contribution is complicated by the frequent occurrence of permeable tectonic fractures and faults. These lineaments contribute to permeability and production characteristics of many of the studied reservoirs, but because their characteristic flow properties are similar to that produced by karst drainage networks, karst drainage has the potential to be unrecognized. In an attempt to identify and isolate karst drainage system contribution to production, a first pass ‘quick look’ method has been developed by which carbonate reservoirs/fields can be ranked with the objective of assessing the degree that karst influences are present. The quick look method is intended to identify karst products, or the potential for karst products to be present, from which steps can then be undertaken to establish wheter a karst drainage system impacts optimum oil productivity.
Non-Upwind Versus Upwind Schemes for Hyperbolic Conservation Laws in Porous Media
Authors: Edwards M. G.
Published: December 2007

Standard reservoir simulation schemes employ upstream weighting approximations of the multi-phase/multi-component convective fluxes. The upstream definition depends upon the direction of the local phase velocities.

This paper presents novel convective flow approximation schemes in a non-upwind finite volume framework, which avoids both upwinding and characteristic decomposition, leading to a fundamental simplification of current methods. Stable lower order and higher order monotonicity preserving non-upwind approximations are developed.

The schemes are locally conservative and the formulation is consistent in IMPES mode (or sequentially implicit mode), with respect to sign change in wave velocity and mass balance.

Comparisons between velocity upwinding and the non-upwind schemes are presented for gravity segregated flow problems where waves undergo sign changes.
Fault and Fracture Corridors—How to Reduce the Structural Uncertainty for Reservoir Management Optimization
Authors: Bockel-Rebelle M. O. , Dabbour Y. , El Abd Salem S. , Vesseron M. , Silva F. P.
Published: December 2007

The occurrence of discontinuities such as faults, fractures or fracture corridors in the porous rock matrix usually has a strong impact on fluid flow and needs to be addressed carefully during the life cycle of the reservoirs.

The major difficulty in characterizing the hydraulic properties of such systems frequently relates with our ability to integrate all the information in a meaningful way in order to derive the key factors constraining the development, intensity and role of the main fracture type in a given reservoir1.

When the faults/fracture corridors act as baffles or barriers they may delineate compartments and blocks with differential drainage rates and variations in pore pressure. Where flow takes place in both the matrix and along/across the discontinuities, the flow paths can become very complex and the way the two systems interplay may even change with time or with injected/produced fluids.

Likewise, the occurrence of faults identified from seismic or fractures brings some extra complexity to the strategies used for reservoir simulation. Issues like how to characterize the faults at different scales and to perform fault ranking and upscaling may have a strong impact on the way simulation results will match actual reservoir dynamics.
Constraining Geological Heterogeneity in Complex Reservoirs: Implications for Stochastic Modeling and Reservoir Management
Authors: Dronamraju S. V. C. , Finol J. , Koraini A. M. , Zakaria A. A.
Published: December 2007

Building static reservoir model that most accurately represents the geological data and pressure data is the starting point in the reservoir management. A sound depositional model and chronostratigraphic control should be prerequisites for a comprehensive static reservoir model. In addition, structural and sedimentary history, timing of trap formation and hydrocarbon entrapment are essential for analyzing the hydrocarbon system. The lower Miocene sediments of D18 field, offshore Sarawak were studied as a part of Full-field Review. A multi-disciplinary approach was used to constrain the depositional and structural heterogeneities. Synthetic seismograms in every well, tied to the redefined chrnostratigraphic picks provided an overall framework for mapping the structure. Uncertainties in depth maps were captured by using a multiple velocity models, built by integrating stacking velocity and checkshots, guided by horizons, which in turn are anchored at wells by synthetics. The resulting maps have least uncertainty in structure definition and helped better define the top of the main producing unit.

A tentative high-resolution sequence stratigraphic model, constrained by biostratigraphy and palynology is constructed, which enabled a chronostratigraphic framework for reservoirs despite the intense deformation of stratigraphic units. A well constrained depositional model based on cores and eletrofacies correlation was constructed to guide modeling of fluvial and deltaic reservoir bodies in the middle Cycle 2, which are the main producing reservoirs. Majority of the production is coming from the transgressive systems tract (C2M3.0–C2M3.4 reservoirs) below the mid-Cycle II Maximum Flooding Surface (MFS). Initial static and dynamic modeling results of the main producing units present justifiable initial hydrocarbon volumes and exhibit flow behavior that matches history of 19 years of production.
Semi-Analytical Model for Water Vaporization in Gas Producers
Authors: Zuluaga E. , Lake L. W.
Published: December 2007

Gas is initially in equilibrium with water at reservoir conditions. However, once a well is placed on production, the pressure drop that occurs around the wellbore causes an increase in the molar content of water in the gas phase. Water will be vaporized starting from the near wellbore zone where the pressure is small, and form a vaporization front that moves into the formation opposing flow. As water is vaporized, dissolved salts become more concentrated, and eventually minerals will precipitate into the formation. This might cause productivity impairment if water continuously supplies minerals to the wellbore area to be precipitated.

This study has developed a semi-analytical model to predict water vaporization for gas producers. The pseudo-steady state well model solves analytically the pseudopressure equation and uses the results to explicitly evaluate water saturation at each time step. The equilibrium mole fraction of water in the gas phase has been corrected for capillary pressure and salinity effects. A modified equilibrium constant has been derived that takes into account capillary pressure.
A New Reservoir Simulation Model for Understanding Reservoir Performance in the McKittrick Steam Drive
Authors: Hayat A. , Echols D.
Published: December 2007

The high gas price environment of late 2000 led to a decision to shut-in all steam injection at the McKittrick field of Aera Energy LLC. When steam injection resumed in early 2001, a decision was made to plug-back all Lower Sands injection and to move uphole as prescribed in the original depletion plan. In order to better understand the impact on reservoir performance, operational issues, and productivity improvements, a new reservoir simulation model was developed in 2003. Thermal simulation was based on a detailed 3D geological model, which allowed for modeling of complex fluid flow during the steam flooding process with comingled production from the various sands.

A 3-D McKittrick geological model showed that intervening shale intervals had holes ("chimneys") from which steam could have migrated into the Upper Sands from the Lower Sands injection. Simulation results confirmed that steam injected into the Lower Sands had indeed migrated into the Upper Sands through the shale chimneys. Based on our view of the ultimate field recovery, the Lower Sands were less mature than expected at the time of the uphole expansion. A field-wide study based on temperature observation well logging confirmed an areal distribution of remaining hot oil. Simulation sensitivity runs were made to understand the feasibility of returning injection to the Lower Sands within the model area. Draining the Lower Sands through use of horizontal wells was also studied. This paper focuses on the reservoir modeling process and the interpretation of simulation results for understanding reservoir performance.
Premixed Cement Slurry Solves Problems Associated with Conventional Oilwell Cementing
Authors: Merritt J. W.
Published: December 2007

Cementing technologies have advanced incrementally since the practice began in the early 1900's.While additives have been developed to meet specific downhole conditions and goals, the process by which cement is mixed has remained essentially unchanged beyond the initial development of mix-ing equipment specifically designed for oilfield operations.Equipment designed for "on the fly" mixing of dry cement on location has evolved and technological developments such as computer control have improved mixing factors such as den-sity control.However, the goal of delivering a homogenous slurry throughout the job has a finite limit when mixing on the fly no matter how much the mixing equipment is upgraded and is technology assisted.

Batch mixing cement is a commonly used method to average out slurry inconsistencies inherent to on the fly mixing opera-tions.Once mixed, however, the batch mixed cement must be placed immediately because the hydration process has begun and does not allow time to perform slurry performance testing to verify slurry properties and make adjustments.

Recent developments in cement technology have made it pos-sible to mix cement and keep it in a liquid state for extended periods of time.This means that the actual slurry to be pumped downhole can be mixed, tested and adjusted to meet the specific needs of the well.As reservoirs become depleted and exploration in increasingly more hostile environments at the surface and below becomes common, the delivery of a homogenous slurry to meet these conditions becomes a critical factor in the success of a well.

The chemical and mechanical processes involved to inhibit hydration have been described in the literature.[1,2,3] Using case studies, this paper illustrates how this technology has been applied in the Mid-Continent U.S.
The Trouble with Bits – A Holistic Approach to Drilling Optimization
Authors: Hamer D. , Chen D. C-K.
Published: December 2007

Over the last decade the advances in downhole instrumentation have provided increasingly more detailed information about the behavior of drilling systems in real world rather than laboratory conditions. While these downhole systems, now intimately coup led with surface data logging, have provided us with a greater ability to intervene in the process and avoid hazardous conditions, what has proved to be extremely revealing is the detailed post bit run analysis of the data.

This paper sets out to illustrate some of the features that have been observed, how these features have been interpreted, and how this new knowledge of downhole behavior is now being applied to bit selection, BHA design, and the development of new tools.

The paper will explore aspects of the fundamental interaction between drill bits and formations, and how, by making this interaction function optimally, a wide range of associated issues are also addressed. In the course of exploring these issues some of the traditional methods of bit selection and drilling systems design will be shown to be based on incorrect assumptions, and how correcting this situation leads to general and significant improvements in well construction economics.
Implementation of a Fuzzy Expert System for Multilateral Well Completion: Case Studies
Authors: Garrouch A. A. , Lababidi H. M. S.
Published: December 2007

A fuzzy expert system (MULTSYS) has been used for planning the wellbore geometry and completion strategies of multilateral wells in a variety of oil fields from around the globe. The case studies varied from heavy-oil to light oil reservoirs, sandstone to carbonate formations, and high permeability to low permeability layers.

The integrated planning process is customized to fit the reservoir and fluid characteristics, the production requirements and constraints as well. The expert system employs a modular approach. It consists of a number of integrated knowledge modules that provide various conclusions at different levels. Knowledge sources include rule-based modules for horizontal and multilateral styles, lateral-section completion types, and junction levels. For a number of field cases, the system yields predictions that are consistent with industrial practice.

By including a large number of production constraints, reservoir and fluid properties, the expert system provides the drilling engineer with a high-value option for a multilateral configuration. In the event that operational conditions do not allow the execution of the recommended multilateral completion, the expert system recommendation may be used as a basis for a compromise.
Added Value for Producing Assets
Authors: Ray L. I.
Published: December 2007

Today's oilfield is data-rich-but suffers due to a lack of end-user access and analysis of the available information. Important wellhead data that historically has been gathered through daily wellsite visits by operating personnel often goes unobserved because of manpower restraints. Therefore, recognition of operating problems based on such visits or on diagnostic analysis of the available data can be delayed or even lost to the operating company.
CT Study of Liquid Diversion with Foam
Authors: Nguyen Q. P. , Zitha P. L. J. , Currie P. K. , Rossen W. R.
Published: December 2007

The mobility and flow distribution of liquid injected after foam controls the effectiveness of foam-acid matrix well-stimulation treatments and the injectivity of liquid in many foam IOR processes. We present a CT study of liquid injection following foam, in which both mobility and the sweep of liquid are directly determined, the latter by CT imaging. Earlier experimental work is extended in that the effects of foam quality, foam injection rate, post-foam liquid injection rate, and core heterogeneity on liquid mobility and displacement pattern are directly observed. CT images show that liquid fingers through foam rather than displacing it evenly. As a result, one-dimensional models for the displacement cannot accurately represent the process. The formation of the finger is at least partly stochastic: in different experiments in the same core, with similar initial foam states, the liquid finger took markedly different paths through the core. Liquid injected after foam does not simply follow the path of mobile gas in the foam. In these experiments, post-foam brine injection was not qualitatively less effective than post-foam surfactant injection, though there were differences in both post-foam mobility and fingering pattern. Implications for field application of foam-acid diversion in matrix stimulation treatments are discussed.
Changes in Horizontal-Drilling Practices Improve Production From the Hunton Formation: Area Study Comparison
Authors: Booth K. , Bryden P. , Varcoe B. , Hicks T.
Published: December 2007

This paper discusses changes in horizontal drilling practices that have proven to increase production rates, improve return on investment and provide better reservoir drainage for the Hunton formation in various fields in Lincoln County, Oklahoma.An area summary comparison of past and present is included to support the benefit of drilling horizontal wells.

Development of the Hunton formation for dewatering purposes began in about 1996 in this field.Wells drilled in the early life of the project were all vertical wells and resulted in a wide range of initial rates.The field has been developed on 160-acre drilling and spacing units.However, due to low permeability in some areas and apparent vertical fracturing, increased density wells have been drilled in most cases to more effectively drain the reservoir. Horizontal drilling was first attempted in 2000.There are several theories on the primary mechanism of production1 from the Hunton formation, but the most common thought is that the reservoir contains matrix porosity and highly conductive pathways combined with vertical fracturing.The process of dewatering the reservoir allows the hydrocarbons to drain into these pathways and break out of the water to be produced.

The Hunton reservoir is under-pressured and is known to be subject to severe lost circulation intervals during horizontal drilling.The problems associated with lost circulation and directional drilling tools has resulted in early termination of many horizontal projects.Standard mud pulse MWD equipment is severely limited in its ability to function during times of lost circulation.Clear pulse signals cannot be returned to the surface and the amount of lost circulation material that can be used is limited as well.In addition, there is an increased risk of losing drilling tools during times of lost circulation that might cause an operator to call TD prior to the intended target.Altex Resources has been an active operator in this area since 1989 and through joint use of improved drilling practices, application of new technology, drilling team cooperation and EM-MWD telemetry has made significant improvements in the success of horizontal drilling projects.The results of these efforts have been to change the primary development methods from vertical drilling to horizontal drilling for hydrocarbon recovery from these fields.

The process changes described within the paper could be applied to other fields where similar formations are drilled.The end result could be recovery and production of more hydrocarbons per well reducing the time to reach payout and increasing the return on the capital investments.
U.S. Gas Market: Updating the Status and Looking Toward the Future
Authors: Schubarth S. K. , Byrd A. C. , Wickham J. F.
Published: December 2007

The United States Natural Gas Market has moved through some very dynamic events over the past few years.The fact that ninety-eight percent of all gas consumed in the US comes from the North American Continent plays a large part in the lack of stability in pricing of Natural Gas.The nature of the production stream feeding the demand for gas has changed drastically in the past decade.The potential demand for gas during peak usage periods of each year has changed dramatically and the maturity of the available gas development projects have all led to a greatly different market than ten years ago.

This paper will update the status of the US Gas market; the state of US production, the change in demand for gas as prices change, estimations for the potential expansion of gas supply and the need for imported gas from outside of the North American continent.
Effects of Two-Phase Flow in a Step-Down Test
Authors: Linroth M. A. , Ferreria C. R. , Valenzuela A. M.
Published: December 2007

Occasionally during a pre-frac injection test the observed friction pressures are much higher than expected. These tests have frequently led to significant delays and expense in tight gas wells re-perforating the interval to be fractured in order to remove this ‘excess near-wellbore friction’ pressure. This paper presents a method to identify and mitigate the effects of two-phase flow during an injection test. Examples are presented which encountered very high apparent near-wellbore friction pressures that were actually due to two-phase flow. Subsequent testing with 100% liquid injection revealed normal near-wellbore friction pressures. A technique of repeating the test after a variable shut-in time has routinely served to eliminate the need for a costly and time-consuming re-perforating job.
Integrated Modeling of the Mature Ashtart Field, Tunisia
Authors: Bischoff R. , Bejaoui R.
Published: December 2007

Ashtart, a large fracture enhanced carbonate oil field offshore Tunisia, required a new reservoir model with high prediction confidence to optimize tail end production and to evaluate its remaining upside potential requiring drilling or tertiary recovery methods. Due to the complexity of the field, a synergistic approach was adopted by teaming up the different disciplines and partners.

This approach entailed the creation of a fine scaled structural and petrophysical 3D matrix geomodel. The model was subsequently scaled up and supplemented with observed dynamically acting features such as fault or fracture flow paths and flow barriers. Modeled matrix permeabilities were systematically adjusted to match established well productivities, without arbitrarily changing flow conditions in the vicinity of wells.

Crucial to this process were not only thorough studies of fracture distributions and attributes, but also the integration of all observed fluid dynamic aspects. Pressure transient analyses proved to be a valuable tool, leading to consistent effective permeabilities and the identification of previously unknown lateral and vertical boundaries. Superior history matches following iterative numerical modeling demonstrate the success of this single permeability modeling approach with improved prediction capabilities.
Integrating Rigorous Completions Optimization into Full Field Geocellular and Simulation Modeling
Authors: Sobernheim D. W. , Iwere F. O. , Luneau B. A. , Apaydin O. , Aly A. M.
Published: December 2007

In this paper, we will present workflows that incorporate two traditionally distinct disciplines within the petroleum engineering and geological domains: rigorous single-well completion optimization and field geocellular and simulation modeling. W e explore the details of this workflow and discuss the benefits of tightly linking the two disciplines. This paper describes an example of the workflow application to a commingled stacked tight gas play in the Rocky M ountains of the United States.

In commingled stacked tight gas pay, gross intervals of thousands of feet are completed to enable maximum productivity. Typically seen are interbedded sequences of fluvial sandstones intermixed with shales, coals, and silty-sand deposits. Because of the heterogeneity seen on various scales, field modeling provides value in deciding optimum well drilling density, determining well location geometry based on hydraulic fracture azimuth and drainage pattern, and modeling various economic scenarios of development.

M odels were built by integrating the seismic, petrophysical, geological, and hydraulic fracture data generated by different disciplines. The vertical and areal resolutions of the model were dictated by sand body sizes, reservoir gross thickness and heterogeneity, and fracture stages. The size of the hydraulic fracture jobs and well spacing were critical considerations in the selection of simulation cell sizes. M ajor challenges included upscaling both the geological features and the hydraulic fracture properties to simulation model scale in a reasonably accurate manner.

A streamline-based flow model was utilized to upscale geological features. The model that best captured both the volumetric and the flow characteristics was chosen for further simulation modeling. Single-well and sector models were used to approximate the fracture properties that would be used in the final simulation model. The models were calibrated to the behavior of the wells and then used for forecasting performance after stimulation. A software program that took into account production and economic information was used for well and field development planning.
Patented Innovations in Casing Plungers Increase Production in Marginal Oklahoma Panhandle Wells
Authors: Moore R. L. , Mayfield W. O.
Published: December 2007

The unreliability of casing plungers has diminished their appeal as an effective solution for removing accumulated well bore fluids that severely curtail production in marginal stripper wells. For decades, the primary cause of failure points to the sealing cup design and the adverse reactions of cup material to well bore conditions. A new cup design and mechanical innovations restore the appeal of casing plungers as a reliable tool to increase production in a broad range of marginal well conditions. Production increases, extended cup life, and reduced operating expenses have been achieved.
Doubling Infill Well Performance in the Mene Grande Field of the Costa Bolivar Region: Case Study
Authors: Rodriguez E. , Herring T. , Gomez H.
Published: December 2007

This paper presents the results of a Material Balance Study in the Mene Grande field, in the Lake of Maracaibo of the region of Venezuela. The study represents the continuation of ongoing subsurface evaluations, which have been the subject of previous publications. The identification and confirmation of the major drive mechanisms and source of water encroachment in the field has led to successful use of traditional Material Balance techniques, where different areas are selected in order to determine the viability of infill well locations.

Prior to obtaining a clear understanding of the subsurface drive mechanisms, infill drilling was based on neighbor well production and reservoir thickness. The results of the infill locations based on this type of evaluation were highly variable and somewhat disappointing. Although simulation modeling was used initially, subsequent well results indicated large discrepancies between the static models and the actual field results. Once these discrepancies had been reconciled, a consistent understanding of the reservoir performance began to develop.

This paper presents the results of applying material balance techniques to reservoir sectors incorporating entire production history and pressure of the neighboring wells to the future infill target. Each sector was matched to the observed pressure, which again showed signs of a secondary support mechanism developing from the reservoir mudstones. It is in fact this secondary pressure support, which allows for higher production from the recent infill wells. A comparison of the completed wells using this methodology and the wells that were located without it is shown indicating a clear and significant benefit to production rates.

This methodology can be considered as a first step towards the construction of a full field 3D model. The proposed methodology is simple and easy to use. This case study clearly demonstrates, that subsurface success depends more on correct understanding of the reservoir rather than the degree of complexity with which it is modeled.
Numerical Simulation of Fully Coupled Fluid-Flow/Geomechanical Deformation in Hydraulically Fractured Reservoirs
Authors: Garcia J. G. , Teufel L. W.
Published: December 2007

A fully-coupled geomechanics/fluid-flow simulation model has been developed to study the behavior of the pore pressure and stress distribution in a hydraulically fractured well-reservoir system. The 3D finite difference, fully implicit model takes into account the non-linear poroelastic deformation of the reservoir rock. The numerical model incorporates a local grid refinement around the perforation depth. Equations that govern fluid flow are coupled with the equations that govern rock deformation in the fracture and the reservoir, then the resulting equations are solved numerically under different reservoir-fracture conditions. The initial and boundary conditions used in the solution of the equations are defined as follows: (i) Zero incremental pressure and displacements at initial conditions and (ii) Closed system for the fluid flow model, non-deformable boundaries. A laboratory-derived stress-dependent permeability correlation is introduced to compute the permeability in both the rock without fracture and the fractured rock. The use of this correlation avoids the need to have initial permeability values and these values are computed using the effective stress acting on the rock. Simulator is applied to selected simulation examples to show the effects of isotropic and anisotropic stress states on the fracture shape and distributions of fluid pressure and vertical and horizontal stresses.
Oil Recovery by Near-Miscible SWAG Injection
Authors: Sohrabi M. , Danesh A. , Tehrani D. H.
Published: December 2007

We present micromodel visualization of pore-scale displacement mechanisms and fluids distribution during recovery of residual oil by near-miscible Simultaneous-Water- And-Gas (SWAG) injection under conditions of very low gas-oil interfacial tension (IFT) and negligible gravity forces. A 3- phase fluid system with gas-oil IFT of 0.08 mN/m, representing a near-miscible fluid system, together with high-pressure (5100 psia) micromodel were used for the flow experiments.

We demonstrate that in near-miscible SWAG injection, the oil recovery continues significantly and almost all of the oil that has been contacted by the gas will be recovered, after the main gas breakthrough. This oil is recovered by a microscopic mechanism, which is strongly linked to the low IFT between the oil and gas and to the perfect spreading of the oil over water, both of which occur as the critical point is approached. We have performed experiments with different SWAG (gas/water volumetric) ratios and we show that the ultimate oil recovery during SWAG injection is almost independent of SWAG ratio, within the tested range of 20 to 50%. This makes SWAG injection an attractive IOR process especially for reservoirs where continuous and high rate gas injection is not possible (e.g. due to supply constraint). In oil reservoirs that cannot export gas (remoteness from the market) WAG (for abundant gas volume) or SWAG (for low or high volume of gas) can be implemented.
A Systematic Approach to Predicting Liquid Loading in Gas Wells
Authors: Guo B. , Ghalambor A. , Xu C.
Published: December 2007

Loading up of liquids in wellbore has been recognized as one of the severe problems in gas production for many years. Accurate prediction of the problem is vitally important for taking timely measures to solve the problem. Although previous investigators have suggested several methods to predict the problem, results from these methods often show discrepancies. Also these methods are not easy to use due to the difficulties with prediction of bottom hole pressure in multiphase flow. An accurate and easy-to-use method is highly desirable. This paper fills the gap.

Starting from Turner's analysis for prediction of the minimum gas velocity for liquid removal, the minimum kinetic energy of gas that is required to lift liquid droplets was determined in this study. In order to compare gas kinetic energy with the minimum required kinetic energy, a 4-phase (gas, oil, water, and solid particles) flow model was developed for mist flow. Applying the minimum kinetic energy criterion to the 4-phase flow model resulted in a closed form analytical equation for predicting the minimum gas flow rate.

The kinetic energy theory indicates that the controlling conditions for liquid drop removal in gas wells are bottom hole conditions rather than top-hole conditions. Our case studies show that Turner's method with 20%-adjustment still under-estimates the minimum gas velocity for liquid removal, and the newly developed equation is more accurate than Turner's method. The new method is easier to use than other existing methods. This paper provides production engineers with a systematic approach to predicting the minimum gas production rate for the continuous removal of water and oil from gas wells. Engineering charts are provided for two typical tubing sizes and wellhead pressures.