bluuebunny/crossref_metadata_2025_split huggingface dataset:
Relative Roughness Chart for Internally Coated Pipes (OCTG)
Authors: Farshad F. , Garber J. 
Published: December 2007

Abstract
The object of this paper is to furnish the engineer with a simple means of estimating the absolute surface roughness, e, and relative roughness, e/D, for internally coated pipes (OCTG). It is very important for design engineers in the oil and gas industry to know the values of surface roughness and relative roughness to properly select, design and install the tubing string. A tubing string is the critical part of the completion program. The tubing must be selected so that production operation can be carried out efficiently; it must be designed against failure from tensile forces, internal and external pressure and corrosive actions. In addition, it must be designed in such a way that maximum production rate and total optimization of the production system is achieved. In 1944, Moody 1 prepared a plot of relative roughness, e/D versus pipe diameter, D, for a number of materials. Moody's1 relative roughness correlation was based on experiments on pipes artificially roughened with sand grains. Moody 1 did not provide the relative roughness plot for internally coated pipes, nor did he perform a regression analysis of the data to provide functional forms of the equations relating relative roughness, e/D, as a function of pipe diameter, D. Currently, internally coated pipes are being utilized in the completion of oil and gas wells worldwide. Consequently, absolute surface roughness and relative roughness values of internally coated pipes are needed by practicing engineers to properly model the hydrodynamics and optimize the production rates in wells 2,3,4. It is important to emphasize that dimensional analysis suggests that the effect of surface roughness is not due to its absolute dimensions, but rather to its dimensions relative to the inside diameter of the pipe, e/D.
Estimating Pore Pressure and Permeability in Massively Stacked Lenticular Reservoirs Using Diagnostic Fracture-Injection Tests
Authors: Craig David P. , Brown Ted D. 
Published: December 2007

Abstract
How does one determine pore pressure and permeability in a well containing 26 reservoirs when pressure-buildup tests are impractical and wireline formation testers have proven ineffective? Operating companies often face this challenge when completing massively stacked lenticular tight-gas sands. During early field development, the pore-pressure differences between sands may be inconsequential to the completion and production of the well; however, as infill wells are drilled, individual sands may be pressure depleted and jeopardize the completion/stimulation of the remaining sands at original pore pressure.
Tight-gas reservoirs in the San Juan, Uinta, Piceance, Greater Green River, and Wind River basins contain fields with individual sands demonstrating pore-pressure depletion. Since many of the massively stacked lenticular sands are stimulated using limited-entry fracture designs, one or two depleted sands can effectively divert an entire fracture treatment from sands at or near original pore pressure.1
This paper describes how multiple diagnostic fracture injection tests are used to (1) identify pressure-dependent leakoff, e.g., from fissure opening (natural fractures); (2) identify pressure-depleted sands; (3) estimate gas permeability; and (4) optimize multiple sand completions. The analysis methods include G-Function analysis for pressure-dependent leakoff, pore-pressure estimates calculated from the stress-depletion relationship of the reservoir rock, and permeability estimates from "conventional" before-closure leakoff analysis and the modified Mayerhofer method.
Fast, Approximate Solutions for 1D Multicomponent Gas Injection Problems
Authors: Jessen Kristian , Wang Yun , Ermakov Panvel , Zhu Jichun , Orr Franklin M. 
Published: December 2007

Abstract
This paper presents a new approach for constructing approximate analytical solutions for one-dimensional (1D), multicomponent gas displacement problems. The solution to mass conservation equations governing 1D dispersion-free flow in which components partition between two equilibrium phases is controlled by the geometry of key tie lines. It has previously been proven that for systems with an arbitrary number of components, the key tie lines can be approximated quite accurately by a sequence of intersecting tie lines. As a result, analytical solutions can be constructed efficiently for problems with constant initial and injection compositions (Riemann problems). For fully self-sharpening systems, in which all key tie lines are connected by shocks, the analytical solutions obtained are rigorously accurate, while for systems where some key tie lines are connected by spreading waves, the analytical solutions are approximations, but accurate ones. Detailed comparison between analytical solutions with both coarse and fine grid compositional simulations indicates that even for systems with nontie-line rarefactions, approximate analytical solutions predict composition profiles far more accurately than coarse grid numerical simulations. Because of the generality of the new approach, approximate analytical solutions can be obtained for any system whose phase behavior can be modeled by an equation of state. The construction of approximate analytical solutions is shown to be orders of magnitude faster than the equivalent coarse grid compositional simulation. Hence, the new approach is valuable in areas where fast compositional solutions to Riemann problems are required.
A Novel Approach to Interwell Tracer Design and Field Case History
Authors: Cheung Stephen , Edwards Aimee , Howard John 
Published: December 2007

Abstract
This paper describes new ways to design Interwell Tracer studies and presents the successful results of a field trial conducted at the Arrowhead Grayburg Unit in Lea County, New Mexico. This is the first incidence of using existing production data to successfully design and implement an interwell tracer program as well as accurately predicting the sequence of breakthroughs. An in-house developed computer program was used to select the injection well and monitoring wells. Two tracers were injected into the injection well. One type was a novel neutralized halo-acid tracer (Isotag) and the other was a fluorescent dye, Rhodamine, to ensure that the extremely quick breakthroughs were caught. We monitored tracer breakthroughs with an in-line fluorometer system, and collected fluids with automatic samplers. The results showed that within two days, tracers broke through at one of the four wells in a five-spot pattern as well as two producers in offset patterns. Additional tracer later broke through in two of the three remaining producers in the five-spot pattern. The sequence of tracer breakthroughs was a direct correlation with the predictions. The results from this study indicated the probability of a fracture system within the reservoir, and illustrated the state of the fluid dynamics for the test area.
Implementation of a Local Grid Refinement Technique in Modeling Slanted, Undulating Horizontal and Multi-Lateral Wells
Authors: Gökta B. , Ertekin T. 
Published: December 2007

Abstract
Deviated holes and horizontal wells are nowadays more often exercised in developing oil and gas fields because of their potential benefits of increasing the drainage area. Recently, multi-lateral/multi-branch well technology has also been in the spotlight, especially in offshore field development projects. Forecasting the economic feasibility of deviated, horizontal, and multi-lateral wells requires a reliable and accurate representation of these wells in numerical models to mimic their expected production performances.
In this paper, we describe the implementation a local grid refinement method into a three-dimensional simulator to model flow performances of slanted, undulating horizontal, and multi-lateral/multi-branch wells. The constructed model does not utilize an equivalent wellblock radius as used in a conventional wellbore model, but utilizes the residual equation to determine the flow into the well. Physical architectures of wells are approximated as a collection of fine rectangular cells. Only the coarse blocks that are hosting wells are locally refined in all three dimensions. Fine and coarse grids are coupled, and flow equations are solved simultaneously.
The developed model provides accurate results even for early times of simulation for any wellbore architecture (slanted, undulating, multi-branch etc.) under consideration. The model does not require the computation of an equivalent wellblock radius, which may be difficult to determine accurately, especially for horizontal wells located in thin reservoirs. The proposed model can be used as a design tool in developing complex fields; for instance, to determine whether a deviated hole or an undulating horizontal well would be a better candidate in a laminated reservoir with varying vertical permeability. Another application of the model is its potential use in pressure transient analysis as it offers significant capabilities in analyzing the early time data, which contains crucial information for well test analysis.
The model results have been tested against the available analytical solutions and/or the existing numerical codes utilizing wellbore equations for vertical and horizontal wells under both sandface and flow rate specifications, and close agreements are observed. The comparison of proposed slanted well representation against existing models that employ a skin factor to represent the deviation is presented for isotropic and anisotropic systems. Applications of predicting flow performances of undulating horizontal and multi-lateral wells are also demonstrated for various systems.
Correlation of Ultra-low Shear Rate Viscosity and Dynamic Barite Sag in Invert-Emulsion Drilling Fluids
Authors: Dye William , Hemphill Terry , Gusler William , Mullen Gregory 
Published: December 2007

Abstract
The occurrence of barite sag has been a well recognized, but poorly understood phenomenon in the drilling industry. Problems such as lost circulation, well control and stuck pipe have resulted from the occurrence of barite sag. The financial impact of barite sag on drilling costs, usually resulting from rig-time lost while circulating and conditioning the mud system, is not trivial. There are reported incidences where recurring barite sag problems have resulted in the loss of drilling projects.
Although originally thought to occur under static conditions, barite sag is now recognized to occur more readily under dynamic, low shear rate conditions. Industry experts have offered a variety of measuring parameters, based upon empirical data, that only partially correlate with the occurrence of barite sag. The prediction of barite sag in dynamic flow has created an engineering challenge.
The effect of shear rate on dynamic barite sag, for invert-emulsion muds, has been studied and quantified using new and advanced technology. A new field viscometer, capable of measuring viscosity at shear rates of 0.0017 s-1, and an eccentric well-bore hydraulics model were used to develop and understand this relationship. Changes in mud weight as a function of shear rate, hole angle, annular velocity and eccentricity correlate with ultra-low shear rate viscosity.
Based upon experimental results, field technology has been developed to predict the potential for barite sag of invert-emulsion muds and to provide remedial measures through ultra-low shear rate viscosity modification. The efficacy of using traditional rheological measurements as indicators of barite sag potential are addressed.
Optimal Design of Two- and Three-Phase Separators: A Mathematical Programming Formulation
Authors: Grødal Evert O. , Realff Matthew J. 
Published: December 2007

Abstract
Oilfield primary separator units are subject to nonlinear fluid dynamic and mechanical constraints. Their design represents a challenging and important problem. In this paper we present separator design problems for which the lowest cost, optimal, solution is found using sequential quadratic programming techniques. The optimization models utilize existing separator design theories and relationships. They consist of a declarative set of equations and inequalities that is independent of the solution method and hence it is easy to make modifications and the assumptions are clear. The models are outlined and discussed in the context of horizontal separators. The efficiency and effectiveness of the suggested systematic design method are exemplified by two illustrative design cases.
A Multiscale Approach to Production Data Integration Using Streamline Models
Authors: Yoon S. , Malallah A. H. , Datta-Gupta A. , Vasco D. W. , Behrens R. A. 
Published: December 2007

AbstractWe propose a multiscale approach to data integration that accounts for the varying resolving power of different data types from the very outset. Starting with a very coarse description, we match the production response at the wells by recursively refining the reservoir grid. A multiphase streamline simulator is utilized for modeling fluid flow in the reservoir. The well data is then integrated using conventional geostatistics, for example sequential simulation methods. There are several advantages to our proposed approach. First, we explicitly account for the resolution of the production response by refining the grid only up to a level sufficient to match the data, avoiding over-parameterization and incorporation of artificial regularization constraints. Second, production data is integrated at a coarse-scale with fewer parameters, which makes the method significantly faster compared to direct fine-scale inversion of the production data. Third, decomposition of the inverse problem by scale greatly facilitates the convergence of iterative descent techniques to the global solution, particularly in the presence of multiple local minima. Finally, the streamline approach allows for parameter sensitivities to be computed analytically using a single simulation run and thus, further enhancing the computational speed.The proposed approach has been applied to synthetic as well as field examples. The synthetic examples illustrate the validity of the approach and also address several key issues such as convergence of the algorithm, computational efficiency, and advantages of the multiscale approach compared to conventional methods. The field example is from the Goldsmith San Andres Unit (GSAU) in West Texas and includes multiple patterns consisting of 11 injectors and 31 producers. Using well log data and water-cut history from producing wells, we characterize the permeability distribution, thus demonstrating the feasibility of the proposed approach for large-scale field applications.
Increasing Fluid Production by Properly Venting Formation Gas in Insert Chamber Installations
Authors: Hernandez Ali , Perez Cesar , Navarro Ulbio , Lobo Williams 
Published: December 2007

Abstract
Accumulation chambers are generally recommended for wells with low bottom-hole pressure and high productivity index. Insert chamber is one type of accumulation chamber that is used when casing conditions do not allow the installation of double packer chambers or when lowering the point of gas injection bellow the top of the perforations will increase the liquid production.
In normal intermittent gas lift operations the formation gas is constantly being vented to the well head and no gas accumulation can occur. For insert chamber installations, formation gas has to travel downward first through the annular space between the perforation and the outside pipe of the chamber. A complicated two-phase flow process takes place in this annulus with formation gas trying to move upward and accumulate at the top, while the liquid is moving downward carrying some formation gas with it. To avoid the accumulation of formation gas in the outer annular space that can block the liquid flow from the reservoir, it is important to provide a way of venting this free gas to the surface.
Insert chambers are highly recommended in some low static pressure reservoirs located in the northern part of Lake Maracaibo where the perforated intervals are, in many cases, as long as 25% of the total depth of the wells. Unfortunately, the formation gas-liquid ratios, found in these reservoirs, are very high.
An insert chamber without a vent port for the formation gas was initially installed in Lake Maracaibo. In this case, the production was not increased. A down-hole pressure survey showed that, even though the draw-down was considerably increased, the liquid flow rate dropped drastically when only 20% of the chamber was filled. A second installation with vent port for the formation gas was installed in the same well and the production increased by 70%. A down-hole pressure survey indicated that in this case the liquid flow was considerably higher. Details of the pressure surveys and the completions installed in both cases are given in the paper, together with a simple procedure to estimate the daily production of a new insert chamber installation.
Inflow Predictions and Testing While Underbalanced Drilling
Authors: Larsen Leif , Nilsen Finn 
Published: December 2007

Abstract
With increased interest in underbalanced drilling, including coiled tubing drilling, the importance of realistic inflow predictions and the potential for formation evaluation based on rate measurements is also receiving increased attention. This paper addresses these points by introducing new models for inflow predictions at various levels of complexity and accuracy for spreadsheet and calculator applications. The methods can handle both homogeneous and layered reservoirs, and essentially traps the expected formation response within a narrow range based on drilling speed and the ratio of vertical to horizontal permeability.
Evaluation of Depressurisation, Miller Field, North Sea
Authors: Beecroft W. J. , Mani V. , Wood A. R. O. , Rusinek I. 
Published: December 2007

Abstract
This paper describes analysis of a potential depressurisation project for the Miller field, North Sea. Depressurisation is an option to enhance the late life reserves of the field. One challenge of the Miller depressurisation project is to mobilize the gas resources in an undersaturated oil reservoir.
Laboratory and simulation work were used to assess the possible benefits of depressurisation at Miller. Published work from the Brent depressurisation project provided a starting point to assess the potential risks of a project at Miller. Uncertainty analysis was performed to quantify the economic impact of each risk in the Miller project. The analysis was very flexible and provided a rapid assessment of the issues which had most economic impact. This approach minimized the number of reservoir simulations typically required to conduct an uncertainty study.
Mobilization of gas at Miller is found to have a significant impact on production profiles and project economics. A well test to measure critical gas saturation in the field is proposed. Strategies to mitigate the impacts of unfavorable critical gas saturation are discussed.
Using Artificial Intelligence to Corellate Multiple Seismic Attributes to Reservoir Properties
Authors: Balch R. S. , Stubbs B. S. , Weiss W. W. , Wo S. 
Published: December 2007

Abstract
Well data gives precise information on reservoir properties at specific field locations with high vertical resolution. 3D seismic surveys cover large areas of the field but reservoir properties are not directly observable due to poor vertical resolution. For this paper, a new methodology has been developed and tested for relating reservoir properties at the well-bore to sets of seismic attributes, in order to predict reservoir properties in two zones of the Nash Draw field in SE New Mexico. Over 350 seismic attributes can be used in regression analyses of reservoir properties. Since using all attributes is computationally unfeasible and labor intensive, fuzzy logic is used to select the most statistically significant attributes for developing regression equations for individual reservoir properties. Non-linear regressions were used, as individual attributes had low correlation coefficients when cross-plotted with reservoir properties, and neural network architectures were developed to relate the selected attributes to each property. In each case the output data used for training was a reservoir property, porosity (ϕ), water saturation(Sw), or net pay, from 19 wells in the field. Each property was estimated using a neural network trained to CC=0.8 or higher using the highest ranking seismic attributes as inputs. The validity of the solutions were tested by removing three wells from the training data, re-computing the weights, and predicting the three absent points. These tests were applied three times for each reservoir property, with different points removed. Each network accurately predicted these nine test points and the solutions are considered robust. ϕ, Sw, and net pay maps were generated using the regression relationships and the seismic attributes at each seismic bin location. Pore volume (ϕh) and hydrocarbon pore volume (hϕSo) maps were derived from those reservoir property maps. These new techniques maximize both the well control and seismic data and generated useful maps for targeted drilling programs in the field.
First Four Water Shut-Off Treatments in ONWJ Field: Design, Execution, Evaluation, and Strategy for the Next Treatments
Authors: Wibowo Wahju , Gould John H. , Munir Antares , Rich David A. 
Published: December 2007

Abstract
Water shut-off treatments have become an acceptable part of well service activities in the past few years for the purpose of controlling and/or decreasing water production and increasing oil production in watered out wells.(1–4) The results of applying polymer water shut-off treatments to several wells producing from a naturally fractured and vuggy limestone reservoir, the Batu Raja Formation, are presented in this paper. The field is located in the Offshore North West Java Field (ONWJ) in Indonesia. The production results show that the water shut-off treatments have proven to be an efficient, low cost method for enhancing oil production in wells which have severe water production problems.
The problem wells in this study were completed in the Batu Raja Formation, which has an underlying active aquifer. The limestone formation is characterized by fractures and vugs, and is connected to the surrounding reservoir through a complex system of fractures and channels. Since the vertical channels and fissures are the dominant feature of the reservoir behavior, and because very high permeabilities of up to 20 Darcies have been observed in some well tests, severe water production is the most common problem in this reservoir. Generally, the water cut increases from 0 to 70% within the first six months of production. Initial production rates are around 1500 BOPD and wells are finally shut in due to excessive water production.
The polymer water shut-off treatments were performed on the wells with varying degrees of success. Water cuts decreased by 10–20% and the oil production rates increased from 0 to 175 BOPD. Overall, the water shut-off treatments were successfully performed in the ONWJ Field and the expenses of the treatments paid out within two months. This successful result demonstrates the viability of the treatments as an efficient low cost enhanced oil recovery project.
This paper also discusses injectivity analysis of the polymer solution using a modified Hall plot method. Detailed successful field results will be presented for each treatment. Also presented are a discussion of how to apply the treatments and recommendations for future work.