bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

Abstract
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

AbstractGas 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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

SummaryIn 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

ABSTRACT
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

Abstract
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.