bluuebunny/crossref_metadata_2025 huggingface dataset:
Thermally Stable Polycrystalline Diamond Cutters for Drill Bits
Authors: Radtke Robert P. , Riedel Richard , Hanaway John
Published: December 2007

Current research has developed an improved ENDURUSTM TSP (thermally stable polycrystalline diamond) cutter and the potential to increase rate of penetration and bit life in hard and abrasive rock. PDC (polycrystalline diamond) wear rates increase exponentially above 700 °F (372 °C), and PDC fails structurally at 1350 °F (750 °C). The ENDURUS™ cutter differ from all forms of PDC and TSP materials in that they maintain a constant wear rate up to 2192 °F (1200 °C) and are stronger to withstand drilling impact forces. TSP cutters have not generally been economic due to low ROP with small available sizes that are surface-set in drag bits, and because of insufficient attachment and impact strength in the larger self-sharpening PDC configurations. All types of commercially available TSP have insufficient fracture resistance for most applications. Low attachment strength and impact resistance is reminiscent of the limitation of PDC in the 1970's before a unique LS induction brazing process was developed in the latter 1970's. TSP can now be brazed with high attachment shear strength using two unique brazing methods – Microwave and Combustion Synthesis Brazing. New TSP manufacturing processes result in a 36% increase in fracture resistance and attachment shear strength over 50,000 psi. (345 MPa). TSP drill bits now have the potential to reduce well cost by 15%, and overall project cost by 7.5%. Thus, the industry could have greater economic incentive to produce deep wells.
Incorporation of Spatial Characters into Volcanic Facies and Favorable Reservoir Prediction
Authors: Tang Hong , Ji Hancheng
Published: December 2007

Compared with clastic reservoirs, volcanic reservoirs are of higher heterogeneity. Lithological facies is one of most important indicators of favorable volcanic reservoir. Traditionally, facies are identified by core observation or log data classification. However, the spatial distribution characters and geological priors, which are important in early stage of exploration, are seldom quantitatively incorporated in facies prediction. Based on previous work, a new methodology is developed to incorporate volcanic spatial information with few well log data (3 wells) to improve the facies prediction accuracy. Such method is applied to volcanic clastic reservoir of Yingchen member, Cretaceous, Xinshan fault depression, northeastern China. Based on the assumption that the residual thickness of volcanic formation is controlled by eruption center, indicator simulation of seismic thickness data is used to estimate the prior probabilities of occurrence of facies. Such prior is combined with well log facies data within a Bayesian framework. Artificial neural network, beta-Bayesian method as well as discriminant analysis algorithm are used to predict log-based facies. Confidence analysis is applied to evaluate the facies prediction. Analysis of variance (ANOVA) proves the overall prediction accuracy is above 82%.

To incorporate updated facies data with geological information (diagenetic facies, potential fractural area and volcanic residual thickness), Indicator kriging algorithm is applied to generate reservoir quality index. Three favorable reservoirs are predicted based on above methodology, which is proved by the subsequent drilling.
Revaporization of Condensate with Methane Flood
Authors: Al-Anazi Hamoud A. , Sharma Mukul M. , Pope Gary A.
Published: December 2007

Coreflood experiments were performed to investigate the effectiveness of methane flood in revaporization of condensate phase from cores. Condensate was accumulated dynamically in cores by reducing the flowing pressure below the dewpoint of the flowing gas mixture used. Two-phase flow was continued until steady state was reached where condensate reached its residual saturation. Methane was flooded through the core to assess the revaporization process.

Methane flooding revaporizes condensate from the core and restores the gas permeability to its initial value, but it is a slow process. Experimental results showed that revaporization of heavy components by methane is very slow process and may require several 10s or 100s of pore volumes to achieve. The revaporization of condensate is controlled by the partitioning of the hydrocarbon components into the flowing gas phase when the pressure is below the minimum miscibility pressure (MMP). Increasing methane pressure and flow rate expedites the revaporization of condensate.

The revaporization of the heavy components in the condensate phase was slightly affected by non-equilibrium behavior at the high flow rates. The return permeability ratio increases with methane volume injected and is relatively insensitive to flow rate, indicating that non-equilibrium effects are of secondary importance. The experimental studies showed promising results for field application.
An Investigation of Non-Darcy Flow Effects on Hydraulic Fractured Oil and Gas Well Performance
Authors: Smith M. B. , Bale A. , Britt L. K. , Cunningham L. E. , Jones J. R. , Klein H. H. , Wiley R. P.
Published: December 2007

The primary objective of hydraulic fracturing is to create a propped fracture with sufficient conductivity and length to optimize well performance. In permeable reservoirs, the design objective is to achieve a Dimensionless Fracture Capacity, CfD, of at least 2. In lower permeability applications, additional conductivity is required (CfD > 10) to allow effective fracture fluid cleanup and optimized well performance. In some tight formation gas applications, conventional cross-linked gel fracture stimulations are not creating the desired fracture dimensions. The potential reasons for the shorter than desired effective fracture lengths are numerous with the most likely being reservoir heterogeneity, excessive fracture height growth, and poor fracture fluid cleanup.

In recent years, there has been much discussion regarding the causes for, or reasons that the dimensions of the hydraulic fracture are shorter than desired. These include: relative permeability effects, fracture fluid cleanup, multi-phase flow, and non-Darcy flow. The former causes and reasons have been investigated in some detail; however, little data has been published regarding the effects of non-Darcy flow on fracture conductivity and effective fracture length. Some in the industry have suggested that tight gas well performance is hindered significantly by non-Darcy flow effects. This view, though potentially correct, is supported by little actual data in the literature. Further, to mitigate this effect, tip screen-out fracturing techniques and larger fracture stimulation designs often utilizing much more expensive ceramic proppants have been recommended and executed even in very low permeability applications. These methods may not be effective in tight gas applications but they surely are more expensive, potentially eroding the economic benefits of fracturing these low deliverability applications. In addition, little actual well performance data has been presented to justify the importance of non-Darcy flow in fractures with much of the justification coming from the use of semi-analytical calculations and spreadsheets.

This paper will document an investigation of non-Darcy flow to hydraulically fractured oil and gas well performance. The investigation will utilize both a three dimensional single-phase numeric finite difference simulator and actual well performance to investigate the importance of non-Darcy flow to hydraulically fractured oil and gas wells. This paper will demonstrate the following: The importance or lack of importance of non-Darcy flow on hydraulically fractured oil and gas well performance,Compare and contrast actual well performance of off-setting wells where sand and ceramics were utilized in East Texas, Trinidad, and North Sea applications,Develop treatment guidelines and fracture design objectives to limit/mitigate the effects of non-Darcy flow across a broad spectrum of fracturing applications.
Methods For Modeling Dynamic Fractures In Coupled Reservoir And Geomechanics Simulation
Authors: Ji Lujun , Settari A. Tony , Sullivan R. B. , Orr D.
Published: December 2007

Proper representation of dynamic (propagating) fractures is important for modeling applications in which the fracture is directly coupled to a reservoir simulator. Such a model, while once applied only to unconventional fracturing applications is now being developed for conventional fracturing techniques (such as fracturing in low permeability reservoirs) as a more realistic tool for modeling both fracture growth and post fracture production responses.

In an uncoupled model (such as conventional fracturing software) the reservoir coupling is usually simplified to a 1-dimensional leak-off model which lends itself easily to construct dynamic grids for the fracture. However, coupled models will generally require a dynamic fracture propagating through a stationary reservoir/stress grid. This creates a well-known grid effect resulting in oscillation of fracture growth with time, and limiting the stability of the model.

In most unconventional fracturing applications, the fracture volume is small compared to injected fluid volume due to high leak-off, which causes a singularity of mass balance constraint or fluid volume in facture. If one were to use a conventional fracturing model with a dynamic grid, this would result in convergence problems due to the high leak off of injected fluid. Also, what is not represented in conventional models is the influence that high leak-off has on the far-field stresses and pressures, which in turn influences the fracturing mechanics.

It is believed that the use of a fully coupled dynamic model such as the one being developed here will generate more realistic representions of the fracture/reservoir response.

This paper presents numerical techniques necessary for the successful development of such a fully coupled model. Four different methods for representing dynamic fracture propagation were formulated. These four methods take into consideration the mutual influence between dynamic fracture propagation and reservoir flow, treat the fracture as a highly permeable part of the reservoir, and use one (common) grid system to model both dynamic fracture propagation and reservoir flow in a fully coupled manner. The individual methods differ by the algorithms, by which the dynamic modification of the transmissibility for fractured grid(s) is derived, and range from an empirical approach to the use of analytical fracture models.
Water Fracs and Sand Quantity: A Barnett Shale Example
Authors: Coulter Gerald R. , Benton Edward G. , Thomson Clifford L.
Published: December 2007

Chief Oil and Gas, LLC has an active drilling and completion program in the Barnett Shale, Newark East Field, Ft Worth Basin near Ft Worth, Texas, USA. This Mississippian age gas producing reservoir consists of naturally fractured shale. Most hydraulically induced fractures have been observed to be more of a network of fractures, referred to as fracture fairways, than the usual ‘planar’ fractures. These fairways apparently result from opening many of the natural fractures allowing for production. All wells must be hydraulically fractured for economic production. The Barnett Shale hydraulic fracturing trend in the last few years has been to water frac with small concentrations of sand. The water frac treatments reported on here have varied from approximately 600,000 to over 1,500,000 gallons and 120,000 to over 400,000 pounds of sand. Most of the wells have been completed in the lower Barnett with a lesser number in the upper and lower. Results from both types of completions are included in this work.

Production histories versus treatment volume and pounds of sand are presented as well as production decline data. Results indicate a much better correlation of production history with sand quantity than with fluid volume.
Rate Superposition for Generating Pressure Falloff Solutions for Vertical and Horizontal Wells
Authors: Peres Alvaro M. M. , Boughrara Amina A. , Reynolds A. C.
Published: December 2007

Although the Thompson-Reynolds steady-state theory has proved useful for explaining the relation between reservoir physics and the pressure/pressure derivative response for both injection and falloff tests, until now, we have been unable to apply this method to construct analytical solutions for the falloff response. In this work, we remedy this defi- ciency by constructing analytical solutions for the pressure falloff response subsequent to water injection at a vertical or horizontal well. By comparison with a finite-difference simulator using grid refinement and a hybrid grid, it is shown that our multiphase flow solutions are accurate.

The falloff solution can be written as the sum of the single-phase falloff solution based on oil properties at initial water saturation plus a multiphase flow term, which reflects the deviation of the total mobility (in the region contacted by injected water) from oil mobility at initial water saturation. The multiphase term is presented as an integral in the vertical well case and a sum of one to three integrals in the horizontal well case. For the purpose of constructing an accurate estimate of the falloff multiphase pressure change term, one can use a series of onedimensional Buckley-Leverett solutions (one for each integral in the multiphase term) and assume that, throughout the falloff period, the total mobility profile in the reservoir is equal to the total mobility profile that existed at the instant of shut-in. Evaluation of each integral in the multiphase term requires the one-dimensional mobility profile constructed from the Buckley-Leverett solution and a corresponding one-dimensional flow rate profile during falloff.

For linear single-phase flow, it is shown that rate superposition applies and we use this concept in a reasonable but ad hoc way to estimate the rate profiles needed to compute the multiphase pressure term.

It is shown that even in cases where falloff data allows one to accurately estimate the properties of the oil zone, knowledge of the multiphase term is critical in order to obtain an accurate estimate of the mechanical skin factor.
New Test Method for Evaluating Quality of Set Well Cements and to Optimize Additive Use
Authors: Jennings Scott S. , Siddiqui Shameem
Published: December 2007

In recent years lot of attention has been given to well cement density settling and cracks in the set cement by over-treating with expansion additives. Conventional methods that examined both settling and cracking due to expansion in set cements needed optimizing. The new method used a high-resolution X-ray CT (computerized tomography) scanner to quantify density differences and heterogeneities in set cement specimens. For the determination of settling, the CT-scanner was highly effective by looking for gradients in the calculated slice density values. For the examination of cracks in the cement, the CT-scanner was highly effective in locating even very small cracks in the cement matrix.

This paper discusses the results from tests for linear expansion and cracking tendencies using three commercial expansion additives. The data presented also showed density segregation of set cements, which may have potential to cause problems with zone isolation. By applying the evaluation technique involving CT based density, heterogeneity and quality assessment parameters, expansion additives were reduced up to 80% from most previously recommended additive concentrations. Similarly, the CT-based technique allowed a thorough analysis of the density segregation in set cement specimens. Findings from these studies have lead to effective re-designing of cement slurries used for critical oilwell cementing operations.
Multiscale Formation Resistivity Imaging
Authors: Frenkel Michael A.
Published: December 2007

Conventional interpretation of array resistivity log data is based on inversion. Multidimensional (2D, 3D) log inversion methods commonly use a single formation model (SFM) for the entire interpretation process. The SFM approach has severe limitations when executing either joint or sequential inversions. Here we present a new multidimensional array resistivity data inversion method that utilizes log-resolution-dependent multiscale formation models (MFM). Each of these resistivity models corresponds to a single log or a subset of the multi-array logs. The resistivity model for a particular subset is determined by the expected resolution of the subset logs. Each subset can contain one or more of the multiarray data logs.

Our method consists of two main interpretation runs. For the first run, we interpret separate subarray logs using a set of MFMs. For the second, we generate the formation resistivity model or its image by inverting the results from the first in the radial direction. The method is applicable to any array log data acquired in vertical, deviated, or horizontal wells. The test modeling and inversion results are presented.
A Pore-Network Study of the Mechanisms of Foam Generation
Authors: Chen M. , Yortsos Y. C. , Rossen W. R.
Published: December 2007

Understanding the role of pore-level mechanisms of foam generation in porous media is essential to the mechanistic modeling and simulation of foam IOR processes. Different foam models assume different foam-generation mechanisms, leading to substantially different algorithms for foam processes. The three pore-level events that lead to foam formation are snap-off, leave-behind and lamella division. As bubbles are created by any such mechanism, gas saturation increases, causing formation of new bubbles by snap-off and leave-behind as gas drains liquid-saturated pores. On the other hand, lamellae are stranded unless pressure gradient is sufficient to mobilize those that have been created. The initial state of the porous medium as surfactant is introduced (fully saturated with liquid, or already partially drained) also affects the different foam-generation mechanisms. To appreciate the roles of these mechanisms, their interaction at the pore-network level must be studied.

We report here an extensive pore-network study that incorporates these pore-level mechanisms, as foam is created by drainage or the continuous injection of gas and liquid in porous media. Pore networks with up to 8,000 pores are considered, with rules for the formation and movement of foam lamellae by the three mechanisms enforced throughout. The study explores the roles of the mechanisms, and, by implication, the appropriate form of the foam-generation function for mechanistic foam simulation. Results are compared with previous studies. In particular, the network simulations reconcile an apparent contradiction in the foam-generation model of Rossen and Gauglitz, and identify how foam is created near the inlet of the porous medium when lamella division controls foam generation. In the process, we identify a new mechanism of snap-off and foam generation near the inlet of the medium.
A Chemical Approach to Prevent Asphaltenes Flocculation in Light Crude Oils: State-of-the-art
Authors: Marques Luiz C. C. , González Gaspar , Monteiro Jair B.
Published: December 2007

This paper describes the state-of-the-art of the phenomena associated to the flocculation and precipitation of asphaltenes as well as the chemical solution used to prevent these problems in the production tubing of light crude oil(42°API) offshore wells in Santos Basin, Brazil. It is also provided a detailed discussion on the efforts to diagnose this light crude tendency to flocculate its low concentration (0.3 %) asphaltenes and on the approach to chemically-inhibit the phenomena. To assess the so-called asphaltenes deposition envelope of the light crude a mono-phase crude oil sample was collected and a suite of experiments was performed in a PVT analysis cell equipped with a solid detection system. As per this study, it was possible to evidence the reversibility of the asphaltenes flocculation process above the bubble point, meaning that these asphaltenes behave much as macromolecules in solution as predicted by the Hildebrand theory.

It is also described the laboratory procedures used to select commercial asphaltenes flocculation inhibitors (AFI) and how the selected ones were evaluated in the field. Within the scope of the field test the following issues were addressed: - how the AFI injection is performed; -how the AFI-free oil samples are collected for the tests on the well site and; - how the existing analytical procedures had to be adapted and enhanced to evaluate the AFI performance in crude oils with so low asphaltenes concentration.

The lessons learned from this pioneer study and the field test are being incorporated to Petrobras newer light-crude oil exploration and production projects.
Oil and Gas Reserves Estimates: Recurring Mistakes and Errors
Authors: Harrell D. Ronald , Hodgin John E. , Wagenhofer Thomas
Published: December 2007

Although most petroleum reserves estimates are prepared by qualified reservoir engineers and geoscientists, there continue to be recurring mistakes and errors in estimates of reserves. This statement is not intended to be presumptuous in any regard, but is based upon observations made by the authors over many years as independent petroleum consultants for both publicly-owned and private exploration and production companies.

This paper presents and discusses the most common mistakes and errors associated with reserves estimates. In addition, guidelines are offered that, if followed, may help reduce the chance of such errors occurring.

It is the intent of this paper to focus on mistakes made in the preparation of reserves estimates rather than to discuss potentially incorrect applications of petroleum reserves definitions. It is clearly not the intent of this paper to interfere with the necessary judgment the reserves evaluator must employ in preparing reserves estimates.

It is inevitable that adherence to applicable reserves definitions must be recognized in any discussion of recommended practices regarding the estimation of petroleum reserves. A generalized definition of reserves without regard to categories or authorship is: Reserves are estimated remaining quantities of hydrocarbons to be commercially produced from a known accumulation as of a given date under specified definitions and economic conditions.
Challenges in Implementing UBO Technology
Authors: Eck-Olsen Johan , Vollen Elin , Tønnessen Tim
Published: December 2007

In July 2004 Statoil introduced underbalanced drilling technology to the Gullfaks Field offshore Norway. The main driver for this technology was to overcome existing pressure control problems experienced while drilling conventionally through the cap rock in order to reach the reservoir. The project represents the first application of underbalanced drilling offshore Norway. The focus of the process design was on being environmentally friendly; consequently, no hydrocarbons were released to atmosphere or flared during the operation.

This paper addresses the challenges in implementing the UBO technology in Norway. There were issues related to equipment, procedures, standards and personnel. Most of the existing Norwegian requirements and guidelines have been developed for conventional drilling. The UBO surface equipment used by the project had to go through a detailed review and extensive modifications to fulfill the Statoil internal requirements as well as the external Norwegian standards and demands. Special quantitative risk assessment methods and software were developed throughout the project to define risk associated with UBO compared to conventional methods. Procedures, emergency measures and contingencies were established to ensure a safe operational environment for personnel at any time. Interfaces with existing platform production facilities had to be made in order to process produced gas and liquid hydrocarbons thereby ensuring an environmentally friendly operation. Some of the major challenges were related to communication and teams that consisted of personnel with very different backgrounds working towards a common goal, i.e. the production philosophy with automated processes vs. the drilling philosophy with manual processes. High focus was kept on open communication throughout the project.
Risk-based Decision Support for Planning of an Underbalanced Drilling Operation
Authors: Arild Ø. , Nilsen Thomas , Sandøy Malene
Published: December 2007

As a part of planning the first well utilizing underbalanced drilling technology in Norway, a comprehensive risk analysis is performed, comparing risk associated with underbalanced and conventional, overbalanced drilling. The development of a new risk analysis method is described. It is concluded that for the given case, underbalanced drilling reduces blowout risk considerably.
Polymer-Free Fracturing Fluid Exhibits Improved Cleanup for Unconventional Natural Gas Well Applications
Authors: Fredd C. N. , Olsen T. N. , Brenize G. , Quintero B. W. , Bui T. , Glenn S. , Boney C. L.
Published: December 2007

Hydraulic fracturing treatments in unconventional (coalbed and carboniferous shale) natural gas wells have been successful in stimulating gas production. However, the wells often do not perform up to potential following the treatments for various reasons. Some of the factors that can contribute to the relatively poor performance include low coal or shale permeability, complex cleating and natural fracture networks, gas content and adsorption characteristics, water content, and fracturing fluid interaction with formation surfaces. Fracturing fluid damage in coal formations has been shown to cause significant reductions in permeability, and whole gel leakoff into the cleat networks can further impair production. The same damage mechanisms can impair the production of carboniferous shale formations.

To avoid the damage associated with polymer-based fluids, a coal/carboniferous shale-compatible solids-free (CCSF) fluid was developed for unconventional natural gas well applications. The CCSF fluid is a nitrogen-foamed fluid that was designed to be environmentally friendly to minimize risk to ground water that could be contacted during fracturing treatments.

This study investigates the effects of various hydraulic fracturing fluids including conventional polymer-based fluids, water containing friction reducers, and a coal/carboniferous shale-compatible solids-free fluid on coal and shale pack cleanup. Laboratory coal pack cleanup tests demonstrate a significant reduction in retained permeability with polymer-based fluids. In addition, a high cleanup factor (a parameter introduced to provide a measure of the pressure and time required for cleanup) is required to establish only marginal flow conditions with brine injected in the production direction. Even water containing low concentrations of friction reducer may result in less than 50% retained permeability. The CCSF fluid provides 70 to 100% retained permeability and a low cleanup factor for effective coal pack cleanup with coal samples from seven coal basins in North America. Similar improvements were observed with carboniferous shale pack cleanup tests.

Field case histories in coal and carboniferous shale formations are consistent with laboratory observations and demonstrate a dependence of fracture cleanup on retained permeability and the cleanup factor measured in the laboratory. Production results demonstrate a 30 to 60% increase in production with the CCSF fluid compared to conventional fracturing fluids in coal and carboniferous shale basins in the United States.
A Mechanical Methodology of Improved Proppant Transport in Low-Viscosity Fluids: Application of a Fiber-Assisted Transport Technique in East Texas
Authors: Engels J. N. , Martinez E. , Fredd C. N. , Boney C. L. , Holms B. A.
Published: December 2007

Several different hydraulic fracturing treatment design methodologies have been adopted and used with varying success in East Texas and, specifically, in the Cotton Valley Sand Formation. Treatment designs have ranged from massive hydraulic fractures using crosslinked polymer fluids to low proppant concentration slickwater treatments (waterfracs) using only water plus a friction reducer. Operators have varying opinions regarding the benefits of the various design approaches, with the only common conclusion being that hydraulic fracturing must be employed to commercially produce hydrocarbons from these tight formations. The major design challenges include the need for long fractures, relatively limited height growth, good proppant coverage over the entire fracture surface, and low proppant pack damage. Neither conventional fracturing treatments nor slickwater fracturing treatments address all of these issues.

To meet the challenging design requirements, a new design methodology in which fibers are added to the fracturing fluid has resulted in added benefits for operators. The fibers assist in the transport of proppant based on a mechanical suspension mechanism and prevent proppant settling during fracture closure. As a result, the fluid viscosity is no longer the main factor in proppant transport and significantly lower polymer concentrations can be used without compromising proppant transport. For example, the polymer concentration used in several successful treatments at BHST in excess of 250°F has been reduced by about 50% when used in conjunction with the fibers. The lower fluid viscosity allows for the creation of the desired fracture geometry with controlled fracture height growth. In addition, reducing the polymer concentration has largely been accepted as a means to increase fracture conductivity. The use of fibers in conjunction with the polymer fluid is a new approach that has allowed for additional reduction in polymer loadings while still maintaining excellent proppant transport in over 90 jobs pumped to date.

The purpose of this paper is to share the fracture design methodology incorporated for several operators completing wells in East Texas. Typical job designs with fluid rheology and laboratory conductivity data are presented in conjunction with the placement success when using the fiber assisted transport design methodology. Initial production results are reviewed and compared to offset wells that have been stimulated using conventional methods.
Reservoir Management Using the Illinois State Geological Survey's Waterflood Database
Authors: Cokinos James S. , Huff Bryan G. , Frailey Scott M. , Seyler Beverly , Grube John P.
Published: December 2007

A digital database of the waterflooded oil reservoirs in Illinois was created as part of the DOE PUMP II program (Contract DE-FC26-02NT15132) to develop geographic information system-based (GIS) play portfolios to improve oil production in the Illinois Basin. The database was compiled from data on paper forms that are submitted annually to the Illinois State Geological Survey (ISGS) by petroleum operators. Attributes collected from the forms include annual and cumulative oil production, water injection and water production. Detailed oil reservoir information such as reservoir pressure, porosity, permeability, API gravity of the oil and depth of the waterflooded horizons are also submitted.

To help producers identify underdeveloped areas in existing oil fields, a strategy was devised and implemented to transfer the digital databases, data manipulation methods and GIS map layering capabilities to petroleum operators through an internet mapping server (IMS). Color coded pay maps and waterflood unit maps were used to identify horizons and units that are currently being waterflooded or were waterflooded in the past. The layering capabilities of the ILoil ArcIMS website could then be used by operators to locate potentially overlooked or bypassed reserves. This database should be available in late fall of 2004.

Using data available in the newly created database, we have used traditional waterflood and reservoir surveillance tools to compare oil reservoir responses in 3 Mississippian Reservoirs. The primary means for making comparisons between waterflooded units is the recovery plot and the recovery derivative. Representative decline curves and oil recovery curves are developed on a per unit/formation basis. These tools are designed to assist in a "first pass" assessment of individual waterflood patterns within a unit or a unit to unit comparison within a field.
Production Analysis of Coalbed Wells Using Analytical Transient Solutions
Authors: Pinzon Claudia L. , Patterson Joseph
Published: December 2007

Coalbed gas formations are an important part of the world's natural gas resource. The energy industry classifies these formations as "unconventional gas reservoirs" and is continually looking for methods to economically develop them. Engineers use various methods of computer simulation to predict performance of coalbed gas formations. There is a tendency to use numerical simulation to predict their performance because of the complex production behavior of coalbed methane wells in the early life of a well. However, reservoir simulation may not be practical for situations in which individual wells need to be analyzed rapidly8. One popular production analysis method is to analyze flowing production data using analytical techniques and type curve matching approaches. These analytical techniques are used to estimate reservoir properties from the matching of the historical data. In this study, public domain production data from producing U.S. coalbed methane basins has been used to illustrate analytical solutions and type curve matching for coalbed wells. The analyses include the use of analytical solutions for coalbed wells that take into account gas desorption from coal using isotherm data, analytical solutions for conventional gas reservoirs and Arp's decline curve analysis. It is assumed single gas phase, and that water production is minimal.
Field Application of New Lightweight Proppant in Appalachian Tight Gas Sandstones
Authors: Myers Roger , Potratz Jimmy , Moody Mark
Published: December 2007

Stimulation treatment designs must provide a delicate balance between completion effectiveness and economical viability. Service company research and development dollars have historically been spent to find the most cost effective treatment fluid for tight, gas-bearing zones. Typically, the focus of this research has been on fracturing fluids and viscous fluid proppant transport.

Thin banking fluids have been proven to be a cost effective fluid for tight gas zones in the Appalachian Basin, but significantly longer and more effective propped fractures are tough to achieve due to poor proppant transport. There are several factors that affect proppant transportation in a fracture, but one most often overlooked is proppant density. In a paradigm shift from focusing on fluid properties for proppant transport to focusing on proppant characteristics for proppant transport, recent technological advances have been applied as a solution for the Appalachian Basin's cost cutting – production enhancement dilemma. In several detailed case histories from New York, Pennsylvania, Ohio and Northern West Virginia, a novel lightweight proppant has been pumped in an effort to achieve the balance of a more effective fracture within tight economical constraints. The treatment effectiveness of the new lightweight proppant will be analyzed to determine if this new technology truly is a cost effective, production enhancing tool for one of the toughest basins to operate in based on well economics.

Stoke's Law calculations indicate that a lightweight proppant with a specific gravity of 1.25 g/cc will have a terminal settling velocity four times less than white Ottawa sand of the same mesh size, 20/40. A simple single phase gas simulator was used to determine initial flow rates and cumulative production for a series of different fracture lengths. It is clear from the simulations that if greater apparent acting fracture lengths can be achieved, flow rates will be increased and reserve-to-production ratios will be decreased.
Simple Field Compressor Automation Delivers Improved Production and Increased Efficiency
Authors: Cramer John W. , Moore Jeff
Published: December 2007

abstract

Gas production decreases as gathering line pressure increases. Gas production from fields populated with plunger lift wells may be especially sensitive to increased gathering line pressures. One method of lowering gathering line pressure and improving gas production is to install field compressors. Gathering line pressure in fields utilizing field compressors may still fluctuate for various reasons beyond the control of the operator. Varying compressor speed can help stabilize the gathering line pressure normalizing and improving gas production. This paper will describe a project designed to investigate the effects and practicality of automating the speed control of field compressors.
Evaluation of a Depleted Gas-Condensate Reservoir for Gas Storage
Authors: Aminian K. , Brannon Alan , Ameri S.
Published: December 2007

A depleted gas condensate reservoir in the Appalachian Basin was considered for Gas Storage. Upon completion of the primary production, a retrograde condensate is present in the reservoir. When depleted gas condensate reservoirs are used for gas storage, gas injection will pressurize the reservoir and will re-vaporize the condensate. As a result, the produced gas during withdrawal cycle will contain heavy hydrocarbons which need to be removed by processing units so the gas does not form liquid phases by retrograde condensation in pipeline.

Peng-Robinson Equation of State (PR-EOS) was utilized to predict the liquid yield during storage cycle. The first step in applying PR-EOS was to simulate the primary depletion and check against the reported primary condensate yields. Upon successful history matching the primary production, the remaining retrograde and residue gas were mixed with pipeline gas to pressurize the reservoir to its original pressure. The fluids were assumed to be completely mixed. Since the volume percent liquid in the reservoir at the end of primary depletion is 5-10%, gravity drainage of the hydrocarbon liquid may be minimized. However, it is possible that the liquid phase can potentially be wetting the pore walls. This may interfere with the mixing and revaporization process. PR-EOS was then used to predict the liquid yield for several separator pressures. In addition, several cases without complete mixing were considered to study the impact of mixing on liquid yield. The results were then utilized for design of surface facilities.
HSE Training, Implementation, and Production Results for a Long-Term Underbalanced Coiled-Tubing Multilateral Drilling Project
Authors: Knight Jeff , Pickles Rob , Smith Bruce , Reynolds Mike
Published: December 2007

HSE training, implementation & production results for a long term underbalanced coil tubing multi-lateral drilling project.

The methods used to safely implement the bp Sajaa CT UBD project from start up issues through implementation will be discussed. To date, 14 wells have been drilled successfully with no accidents, the decline in the gas production for the Sajaa field has been mitigated and additional reserves have been accessed. This has been achieved through a programme of training, teamwork and service company integration leading to new heights of HSE performance for the industry. In addition, the key learning's have been carried forward from well to well to optimise the economics of the project and open up new opportunities previously thought to be unfeasible. Through a series of innovative engineering applications, the future of the project has been secured.
Reduction of Wellbore Effects on Gas Inflow Evaluation Under Underbalanced Conditions
Authors: Aremu O. J. , Osisanya S. O.
Published: December 2007

Proposal

Wellbore storage effects have been identified to significantly smear the accuracy of evaluating reservoir productivity through the fluid outflow rate from the annulus during underbalanced drilling. Such effects have continuously introduced considerable errors in characterizing the reservoir during underbalanced drilling. Conceptually, due to the readily volume changing ability of the gas, wellbore storage becomes a determining factor during underbalanced drilling of a gas reservoir. Wellbore storage could either cause decrease (unloading effects) or increase (loading effects) in the annular gas density depending on the choke opening procedures. Correspondingly, annular fluid outflow rate is considerably affected. Since it is practically difficult to deduct the fluid flow rate due to the wellbore storage from the total fluid outflow rate, reducing the influence of wellbore effects on the evaluation of gas reservoir productivity is presented in this study. Volumetric production analysis at the wellbore-sand face is introduced through a mathematical modeling of inflow of gas bubbles into the wellbore. This mathematical modeling utilizes forces such as the viscous force, drilling fluid ejecting forces from the bit nozzles, buoyancy, interfacial tension, and gas reservoir forces for its analyses. Some analytical results that are overshadowed by wellbore storage are presented and supported by extensive experimental studies.
Use of Foamed Cement in Deep Water Angola
Authors: Benge Glen , Poole David
Published: December 2007

Increased activity in West Africa has improved the availability of many services and materials that were not readily available just a few years ago. Technologies that are commonly used in many parts of the world are now available. One technology used globally in deep water, foamed cement, has become readily available in Angola. Its use in deepwater applications has been shown to simplify well planning and logistics and has resulted in increased success and cost savings on current wells.

This paper discusses the introduction and use of foamed cement in deepwater cementing in Angola. Included is a discussion of logistics associated with foamed cementing and mobilization of crews, equipment and a comparison of this technology against alternate lightweight cement slurries. Discussed are the logistics for specialty-blended cements, including the need to import specialty cement materials or blends, excess inventories required to cover large contingencies and uncertainties, and associated delivery times. An analysis of the introduction of foamed cement to Angola is presented along with the associated risks of the use of both the foamed cement and alternate specialty slurries. On-location operational considerations for foamed cement are discussed and comparisons are made with the requirements for mixing of specialty lightweight slurries.
Proving UBD's Value in Brownfields and Beyond
Authors: Holt Calvin
Published: December 2007

Underbalanced drilling (UBD) is giving brownfields a new lease on life—while UBD technologies in development hold the promise of drilling the "un-drillable well" and reducing cost.

Much of the industry's mindset focuses on traditional drilling and stimulation technologies to exploit brownfields, but we suggest that in many cases the greatest potential for these reservoirs lies in UBD techniques. Emerging methodologies, like managed pressure drilling (MPD), are also moving rapidly into the driller's toolbox to allow him to "walk the line" between extremes in pressure regimes. Or perhaps technologies that reduce the cost of UB drilling and enabling underbalanced completions will be attractive enough to propel the technology across the ‘chasm’. This article discusses real benefits of UBD in mature fields and presents an overview of its new technologies in development.
Integration of a Performance Drilling Motor and a Rotary Steerable System Combines Benefits of Both Drilling Methods and Extends Drilling Envelopes
Authors: Rønnau Hans-Henrik , Balslev Peter Vilhelm , Ruszka Jon , Clemmensen Carl , Kallevig Sverre , Grosspietsch Ralf , Mader Georg
Published: December 2007

Since their introduction in 1997, rotary steerable drilling systems have delivered significant gains in drilling efficiency. In addition to this fundamental benefit, these systems have enabled more challenging wells to be drilled at low risk with a wide range of other advantages, including improved well placement, etc.

Continuous rotary drilling operations do however bring with them certain challenges which must be considered before rotary steering is selected for use. These include instantaneous penetration rate, specifications of rig rotary equipment, casing or drillpipe wear, stress on the drillstring, loss of drilling power through wellbore friction and drilling dynamics.

Using high powered drilling motors, traditional performance drilling has been applied since the early 1990's to improve penetration rates by applying high power and consistent operating parameters directly to the drillbit. This has however been limited to straight holes or the most basic of directional profiles.

A system has been developed which integrates a specially designed high power drilling motor within a high speed rotary steering assembly. By using this new system:

many of the challenges of continuous rotary drilling are mitigated, more complex wells benefit from the advantages of traditional performance drilling, existing drilling envelopes can be extended to further improve field recovery.

This paper discusses the engineering design of the complete system, including the specially designed motor and high speed rotary steering system. The paper then goes on to discuss specific applications where the system should be considered for use, illustrated with results from real examples.
Use of Pressure-While-Drilling Tools to Improve Formation Integrity Test Interpretation
Authors: Akers Jay , Sellers Jay
Published: December 2007

In deepwater drilling, a small margin usually exists between formation integrity and pore pressure. Accurate determination of the formation integrity at casing shoes is paramount to drilling an interval without losing returns. Non-aqueous fluid is often the fluid of choice for deepwater environments, and cold temperatures in the riser result in higher drilling fluid viscosity and gel strengths along with pressure and temperature effects on fluid density. These effects on fluid properties can induce inaccuracies in the interpretation of surface collected data when determining the fracture initiation pressure (FIP) during a formation integrity test (FIT). Downhole pressure technology can be used to more accurately determine fracture initiation during a FIT by measuring the true bottomhole pressure at the formation, thereby eliminating the effects of mud gel strength and varying mud weight in the mud column. The comprehensive pressure data, however, is stored in downhole memory and can only be accessed upon tool recovery or wireline data link. Neither of these options are economically attractive in the deepwater cost environment. However, limited downhole pressure data can be transmitted back to the surface once circulation is re-initiated. This paper presents a field useable method which makes use of limited real-time downhole pressure data to correct interpretation of surface collected data. This method has been compared to over 20 FIT results from actual downhole memory data and yields a close match.
Performance Drilling Onshore Iran - Introducing New Concepts to a Mature Area
Authors: Spoerker H. F. , Doschek M.
Published: December 2007

For a five-well exploration program, a brand new 2000HP onshore drilling rig has been imported from China into the Islamic Republic of Iran. At the time the project started (late 2003), this had been the first international drilling contractor entering into Iran since a brief attempt in 1991.

The wells have been designed to make full use of modern performance drilling, effectively introducing these concepts into an operating arena that has been characterized by almost complete isolation from developments in drilling technology for the last 25 years (since the Islamic revolution in 1979).

The paper presents the initial concept of how to drill these wells, together with the introduction of heightened environmental awareness during drilling operations, as well as the experience in implementing these concepts on the first well being drilled to 15000 ft in the Zagros fold belt onshore western Iran.