bluuebunny/crossref_metadata_2025_split huggingface dataset:
Performance Evaluation of Horizontal Wells
Authors: Kuchuk Fikri J. , Lenn Chris , Hook Peter , Fjerstad Paul 
Published: December 2007

Abstract
Horizontal wells have been drilled in many oil and gas reservoirs. Measuring or calculating the productivity of horizontal wells has been difficult because of their long length in the formation compared with vertical wells and because of the inadequacy of measurements during drilling and production. In this paper, we examine the performance of horizontal wells. First, we review the theoretical productivity of horizontal wells and examine the sensitivity of productivity to well and reservoir parameters. We then compare theoretical and actual productivities from horizontal wells in several oil fields to show that most horizontal wells do not produce at their full potential because of the effects of wellbore and near-wellbore formation conditions right after drilling on cleanup. Second, using field examples, we show that the new integrated production logging measurements can be used to assess horizontal well productivity by identifying productive zones, fluid entries, and determining the fluid distribution (oil, gas, and water) in the wellbore. We also show how reservoir heterogeneity affects the reservoir pressure distribution.
The field examples indicate that horizontal wells have permanent water sumps, regardless of whether they produce water. In these wells, we show that when a large percentage of the wellbore cross section is filled with water, reduced oil entry occurs. To assess the effect of the water sumps, flow restrictions, and noncontributing sections along the wellbore on the well productivity, a numerical model with actual well trajectories and openhole and production log measurements is used to estimate well productivity. These horizontal well performance simulations indicate 30 to 50 percent productivity reduction when they are compared with their full potential.
P. 231
Hybrid Streamline Methods
Authors: Ponting D.K. 
Published: December 2007

Abstract
Streamline techniques offer the possibility of high speed reservoir simulation, but existing methods have some limitations for example, the pressure field is frequently derived using the assumption of incompressible flow. Unlike conventional simulation, material conservation is not inherent in the method, but can act as a check on the accuracy obtained.
Using a pressure equation based on molar density variables, we extend the streamline technique to handle compressibility and depletion. The streamline update then becomes an alternative method of updating the composition field to the usual conservation equations. By using and comparing both methods we can assess the accuracy and speed gains obtained using the streamline approach.
The treatment of wells is an area of interest in streamline simulation. When a number of streamlines enter a producer cell the contribution from each must be weighted carefully, as this defines the solution in the vicinity of the well and the composition of the produced fluid. It should also be possible for fluids to pass through a well completion cell without being produced, for example in the vicinity of a strong aquifer. In order to treat near well effects in detail, we combine a streamline model for the bulk of the reservoir with a more general model near the well.
P. 273
The Integration of Petrophysical Data for the Evaluation of Low Contrast Pay
Authors: Deakin Mark , Manan Wan 
Published: December 2007

Abstract
To date eight gas/condensate fields have been discovered through exploration and appraisal drilling by Carigali Triton Operating Company Sdn. Bhd., Operator of Block A-18, JDA on behalf of its Shareholders Petronas Carigali (JDA) Sdn. Bhd., Triton Oil Company of Thailand (JDA) Ltd., and Triton Oil Company of Thailand Inc., Contractors to the Malaysia-Thailand Joint Authority (MT JA). Sequences 0-II of these fields include stacked shaly sand' reservoirs containing low contrast pay. The suppressed resistivities of these reservoirs are caused by cm-dm clay distributions, which vary between facies, making the identification and quantification of reserves difficult.
An integrated petrophysical approach has been adopted to overcome these difficulties. Borehole image-log interpreted facies are treated as classes of clay distribution, and the log responses of each facies are calibrated to core data, acquired separately for each facies. Saturation-height functions are used with wireline formation pressures to project initial conditions capillary pressure saturations into all cored intervals, providing foot by foot log independent gas volumes. For each facies, the log data and Waxman Smits equation are calibrated to these gas volumes through the saturation exponent (n *) The role of n* as a core-log matching parameter is analogous to apparent fluid density in a core-log porosity evaluation. In addition, gamma ray is used to optimize n* for each facies. Results are supported by the fluid mobility seen on limited magnetic resonance logs, and all other available data.
The technique provides a simple, reliable and inexpensive means to evaluate the hydrocarbon potential of low contrast pay. The determination of formation water resistivity (Rw) is circumvented and data acquisition costs are minimal as the required data has often been acquired for other purposes. In this case study its application will result in a gas reserves up-grade for CTOC, its Shareholders and the Malaysia-Thailand Joint Authority.
P. 327
Profitable Continuous Flow Gas Lift in 18,000 Feet TVD Wells with Low Reservoir
Authors: DeMoss Ed , Ruiz-Garcia Saul , Sarmiento-Mendoza Salvador , Perez-Fuentez Alfredo , Gossell Steve 
Published: December 2007

Abstract
Two fields near Villahermosa, Tabasco, Mexico, have been difficult to produce with gas lift because they are so deep and the reservoir pressure is so low. In both fields 1000 psig lift gas systems were installed several years ago and served effectively for several years. To get a higher lift gas pressure with today's low reservoir pressures, skid mounted motor compressors were installed at ten well sites in 1995-96. Sixteen more compressors were installed in 1997.
In one field, Cardenas, the static pressures and depths range from 2794 psig at 18446 ft to 2712 psig at 18056 ft. This field has twenty-two wells and produces 37,500 bopd. Six wells were gas lifted with the 1000 psig lift gas system. In 1995-96, four compressors were installed at four of these six wells and the production increased 5258 bopd.
The other field Samaria-Iride, has a static pressure of 3342 psig at 14750 ft. This field has fifty wells and produces 107,850 bopd. Twenty-nine wells were gas lifted with the 1000 psig lift gas system. In 1995-96, six compressors were installed at six of these twenty-nine wells and the production increased 6595 bopd.
All of the designs were made with a kick off pressure of 2300-2500 psig using API type IPO valves for unloading. The body of the paper discusses two wells from each field describing the before and after production and the completion schematic.
P. 135
Field Electrification Efficiencies: One Operator's Experience in the Conger (Penn)
Authors: Harris B.W. , May K.R. 
Published: December 2007

Abstract
Several strategies have been employed in Wagner & Brown's Conger field of over 500 beam-pumped wells to reduce electrical power bills. The first involved a decision, early in development, to deliver the highest practical voltage to each wellsite. Later, as well count reached into the hundreds, full understanding of the distribution system, its power flow and line losses, required computer modeling of a combined electrical system that was previously metered by two separate primary meters. That modeling brought about elimination of power factor penalties and reduction of IOR power losses by optimum placement of capacitors.
By coordinating the system protection devices such as primary fuses and upstream reclosers, the system reliability was improved and the production downtime was reduced.
Placement of a digital PME with memory and computer download capability allowing scrutiny of field power usage in 15 minute increments led to overall power demand (KW) leveling and reduction of peak demand through installation of digital pump-time clocks. Current utility deregulation promises significant cost reductions for users flexible enough to alter or otherwise control the way in which they consume electricity.
P. 149
Squeeze Cement Matrix Improves Communication, Increases Efficiency, and Reduces
Authors: Lopez Henry , Renshaw Dave 
Published: December 2007

Abstract
The Wickett Field in the Permian Basin, located 40 miles West of Odessa in Ward County, Texas, is a mature field where squeeze operations occur approximately once per week on each workover rig. Historically, squeeze designs and success ratios have been evaluated individually on a "job by job" basis; this has maintained squeeze cementing costs at a very high level for both the operator and the service company. These costs can include factors such as initial and repeated cement laboratory testing on varying cement slurries, on-site pumping services, cementing additives, surface and down hole equipment, administrative and engineering time of both the operator and service company personnel, rig time, and repeated costs with each squeeze attempt.
For some operators, additional factors can contribute to the complexity of this process such as limitations on a consistent methodology or organized approach to the operational aspects of a squeeze operation. Variations can exist within engineering, field supervisory, and service company personnel as to proper on-site pumping techniques, cement slurry design, or necessary volumes of cement for initial or subsequent attempts. Often times, a very limited established or organized method is in place for "looking back" on the success or failure of any particular cement slurry or operational technique. Finally, an overwhelming amount of selections are available in the design process concerning slurry design and operational techniques.
We will show how an operator, in close association with a service company can establish specific guidelines to manage these complex variations. We will present the methodologies that have reduced the complexity and increased the manageability of an ongoing process. Through these efforts, laboratory testing, administrative and engineering time commitment by the operating and service company personnel, and overall costs in remedial squeeze cementing have been reduced. In addition, these methodologies have improved communications, helped standardized operational considerations, and have increased the probability of successful squeezes on the first attempt.
P. 155
New Exact Spherical Flow Solution With Storage for Early-Time Test Interpretation
Authors: Proett Mark A. , Chin Wilson C. 
Published: December 2007

Abstract
Conventional methods used to analyze early-time formation transient test data are approximate and do not model the entire timewise pressure response. Alternatively, detailed models used for early-time storage or late-time analysis are numerical and chart-oriented, and not amenable to simple physical interpretation. In this paper, the general spherical flow formulation, with wellbore storage, is solved by inverting the Laplace transform to produce a closed-form analytical solution. This new solution reduces to previously published early- and late-time solutions in the respective asymptotic limits. Importantly, the availability of the new solution permits convenient pressure-response-to-theory-matching using the complete time regime (early-, transitional-, and late-time data), rather than the typical late-time matching to the asymptotic limit of the spherical flow regime. The new solution also allows accurate formation evaluation using early- and intermediate-time data only, thereby reducing rig down-time required for testing.
The new analytical solution is derived for the full initial- boundary value problem for transient, compressible, spherical flow using Laplace transforms. In this paper, the Laplace transform is inverted to obtain a closed-form expression for the pressure field, and additionally, expressions for pressure derivative and sandface flow rate are derived in terms of the complex error function. These solutions are compared to existing numerical solutions obtained by approximate transform inversion, and to finite element model results that include the three-dimensional effects of wellbore geometry. The accuracy and interpretation speed of the new solution permits systematic determination of all flow parameters, to include storage coefficient, formation fluid compressibility, permeability, and pore pressure. It circumvents limitations inherent in existing methodologies, e.g., where parameters such as compressibility are assumed a priority.
A new type of drill stem well test tool is also described, and the new solution is used to analyze its field test data. Wireline tester log data examples are analyzed to illustrate the utility and power of the new solution. The examples are used to demonstrate how the new solution saves rig time by using convenient, microprocessor-based, real-time regression analysis to determine formation properties.
P. 167
Analysis of Wireline Formation Test Data from Gas and Non-Darcy Flow Conditions
Authors: Kasap Ekrem , Lee Jaedong 
Published: December 2007

Abstract
In addition to fluid samples, formation testers provide undisturbed formation pressure (p*), as well as mobility and compressibility of formation fluids, essential for estimating initial hydrocarbon in place and recovery efficiency.
Formation tests provide in situ measured permeability and permeability profiles. Recent advancements have been reported in interpretation of pressure test data on liquid saturated formations. For gas formation, however, both compressibility and viscosity are strong functions of pressure; therefore, they are variables during the test. Appreciable temperature change is also observed during gas formation testing. Large gas compressibility and much smaller gas viscosity complicate the analysis. Moreover, gas flow is complicated by non-Darcy flow effects.
In this study, the Gas Formation Rate Analysis (GFRA) technique is developed to analyze gas pressure tests. We calculated gas pseudo-potentials and analyzed variation of pseudo-potential versus formation rate during a formation test by utilizing the geometric factor concept. Forchheimer's equation has replaced Darcy's equation to study non-Darcy flow effects.
The technique is applied to a field test, from which mobility is obtained. The results of the technique are verified by history matching a field test with a 3-D near wellbore simulator, developed for gas formation testing modified for non Darcy flow effects.
P. 183
Porosity Determination in Gas-Bearing Formations
Authors: Quintero Luis F. , Bassiouni Zaki 
Published: December 2007

Abstract
The porosity of gas-bearing formations is determined using empirical models. These models use the porosity values displayed by the density and neutron logs, assuming that both tools investigate the same gas saturation profile. They also assume that the variation of gas density and mud filtrate saturation and salinity has little effect on porosity values. These assumptions could introduce a high degree of uncertainty, specially in case of tight gas sands.
A new model is proposed which uses the density porosity value and a neutron porosity value derived from the reading of the near detector. The model incorporates a parameter depending on the gas density and drilling fluid saturation and salinity. A forward model establishing the neutron and density tool responses under a known set of conditions was used to assign values to this parameter. The inverse model derives the needed porosity values.
In addition to providing a more representative porosity value for gas-bearing formations, the model can also be used to determine the bypassed gas saturation in the flushed zone of the formation. The value of the bypassed gas saturation is used as an indication of the displacement efficiency in water- drive gas reservoirs.
P. 213
CO2 Energized and Remedial 100% CO2 Treatments Improve Productivity in Wolfcamp Intervals, Val Verde Basin, West Texas
Authors: Johnson Raymond L. , Walters Wallace W. , Conway Michael W. , Burdett Bruce S. , Stanley Rod G. 
Published: December 2007

Abstract
Fluid clean-up effects have hampered stimulation success in many tight, naturally fractured sandstone reservoirs. The petrophysical responses of treatment fluid invasion can affect short-term and in some cases long-term reservoir deliverability. Many times reservoirs such as the Wolfcamp intervals, in the Val Verde Basin of west Texas, exhibit better response to CO energized fluids than non-energized fluids. We will present data from a case study of several wells in the Wolfcamp A, C, and D intervals where CO-assisted fluid and 100% CO treatments have significantly improved productivity in both initial and remedial applications.
First, we will include case histories where CO-assisted fluid fracturing and refracturing treatments improved performance over non-energized, fluid treatments, Next, we will describe cases where injections of non-energized fluids systematically reduced production; in particular we will describe a case that was successfully remediated by a 100% CO treatment. Then, several cases will be presented showing sustainable improved responses following 100% CO treatments in previously energized and non-energized fracture stimulated intervals.
P. 255
Development and Field Application of a Delayed Breaker System for Use at High
Authors: Much Michael G. , Franklin Vernon L. 
Published: December 2007

Abstract
It can be difficult to effect a timely fracturing fluid break, after a hydraulic fracturing treatment, in reservoirs above 190 F. Fracturing fluid systems often are quite stable at temperatures up to 300 F. At elevated temperatures the treatment designer is faced with the selection of a fracturing fluid breaker from three main categories: oxidizers, acids and enzymes.
Typical oxidizing breakers systems, used at temperatures up to 250 F, are persulfates often encapsulated by a thin film of polymer. Encapsulated persulfates often "leak" allowing some of the encapsulated breaker to be rapidly released into the fracturing fluid. Early release of oxidizing breaker degrades the fracturing fluid during the fracturing treatment—before the desired time.
Acids can be used as breakers but are usually limited to lower temperatures. In addition, the buffering capacity of the formation and the fracturing fluid can significantly impact the performance of acids and finally, acids are usually less cost effective than other breakers.
Polymer specific enzymes, while an effective breaker at elevated temperatures, do not provide a rapid break in fluids with a high pH.
The industry has developed an appreciation of minimizing gel loadings in fracturing fluids because of perceived high insitu polymer concentrations brought about during fracture closure. For this reason, it is desirable to use breaker systems that do not prematurely attack fluid viscosity, allowing use of the minimum gel loading that adequately transports proppant
A high temperature, fracturing fluid breaker system that circumvents many of the problems discussed has been developed. The breaker system, instead of relying on a micro-thin coating on a very reactive substrate, provides a different approach to the problem. The alternative breaker system discussed here utilizes a non-encapsulated, oxidizing breaker that effects a delayed break by slowly releasing free radicals in water based fracturing fluids, thus degrading fracturing fluids in a controlled manner.
P. 273
Find Grid CO2 Injection Process Simulation for Dollarhide Devonian Reservoir
Authors: Wang Shie-Way , Robertson Steven D. 
Published: December 2007

Abstract
Carbon dioxide injection in the Dollarhide Devonian reservoir commenced in May 1985. Subsequently, CO injection was expanded to an area of the majority southern fault block. As of May 1995, CO injection has been implemented in the entire Devonian formation in five phases. Hybrid CO injection was chosen to be the primary mode of operation. During the course of this project, the operator experienced reduction in injectivity when switching to WAG after injecting a 10% hydrocarbon pore volume CO slug in phases 1 and 2. Oil production consequently decreased due to reduced injectivity. This study was designed to answer operation related questions. We selected a 5-spot pattern in the southern fault block for this study partly because it had the longest production history with hybrid CO injection, and also because the study area was not complicated by faults. Forecasts were made over a period of twenty years for four scenarios. The cause of sustained high water cut at the central producer was also investigated. A fine grid model was used in this study in order to compare more accurately the recovery efficiencies between a single CO slug and hybrid CO injection, and to investigate the advantages of operating at a lower pressure.
P. 319
Gel Treatments for Reducing Channeling in Naturally Fractured Reservoirs
Authors: Seright R.S. , Lee Robert 
Published: December 2007

Abstract
This paper considers some of the reservoir variables that affect the severity of channeling and the potential of gel treatments for reducing channeling through naturally fractured reservoirs. We performed extensive tracer and gel placement studies using two different simulators. We show that gel treatments have the greatest potential when the conductivities of fractures that are aligned with direct flow between an injector-producer pair are at least 10 times the conductivity of off-trend fractures. Gel treatments also have their greatest potential in reservoirs with moderate to large fracture spacing. Produced tracer concentrations from interwell tracer studies can help identify reservoirs that are predisposed to successful gel applications. Our simulation studies also show how tracer transit times can be used to estimate the conductivity of the most direct fracture. The effectiveness of gel treatments should be insensitive to fracture spacing for fractures that are aligned with the direct flow direction. The effectiveness of gel treatments increases with increased fracture spacing for fractures that are not aligned with the direct flow direction.
P. 419