bluuebunny/crossref_metadata_2025_split huggingface dataset:
Novel Inlet Design Expense Range of Operability for Compact Separator
Authors: Barbuceanu Nicolae , Scott Stuart 
Published: December 2007

Abstract
The concept of compact separation is attractive in a number of operating environments. These include offshore and arctic operations where both space and weight are at a premium and subsea and downhole processing where space is very limited. Compact separators often rely on centrifugal forces to enhance the separation process and are therefore highly dependent on inlet geometry. This paper investigates expanding the operational envelope of a compact Gas Liquid Cylindrical Cyclone separator through the use of a novel inlet, which can be easily altered to respond to changing well conditions. To demonstrate the importance of inlet geometry, historical production from the Gloyd-Mitchell zone of the Rodessa Field in Louisiana was examined over a 40-month period. As in most oil field production, there were significant changes in the water cut and GOR. This field data clearly shows that a compact separator equipped with single inlet geometry is not able to perform effectively over the wide range of conditions exhibited in a typical oil field. This paper models the hydrodynamics in the separator inlet. Three different inlet geometries were investigated through the use of a changeable inlet sleeve. New experimental data were acquired utilizing a 7.62-cm I.D compact separator, which was 3.0 m in height. The effect of inlet geometry on separator performance was investigated over a wide range of flow conditions. Fluid viscosities from 1-12 cp and the effect of fluid level within the separator were also examined. The results indicate that the operational envelope for liquid carry-over and gas carry-under can be expanded by more that 300% by altering the inlet to respond to changing field conditions.
Life Cycle Management of Scale Control within Subsea Fields and its Impact on Flow Assurance, Gulf of Mexico and the North Sea Basin
Authors: Jordan M. M. , Sjuraether K. , Collins I. R. , Feasey N. D. , Emmons D. 
Published: December 2007

Abstract
This paper presents an overview of life cycle flow assurance management for a platform/subsea development by focusing on scale control. To illustrate this approach examples of scale control methods for deepwater subsea fields will be cited covering aspects such as (1) treatment of the reservoir prior to production to prevent scale formation within the near wellbore (solids and fluid system for inhibitor deployment), (2) downhole scale control using continuous injection (gas lift, capillary), and (3) squeeze treatments as the production wells move through their life cycle and water cut rises. The management of scale and corrosion issues within a subsea field will be reviewed with examples of an operator moving from combined scale inhibitor/corrosion inhibitor products to single corrosion inhibitor product at the manifold as water cut rise. The scale control within this field was achieved with squeeze treatment residuals protecting the reservoir through the topside process without the need for additional scale inhibitor injection. A review will be presented on how this field could have been developed if all today's scale control/monitoring technology had been available during the CAPEX phase of field development and how this might have an impact on field economics.
The paper will outline the methods used to assess the risk of scale and the associated risk manageability of the problem and review how this risk changes through the life cycle of subsea assists under seawater drive and natural depletion. The process and methods of assessing the risk of scale formation during produced water injection will also be addressed.
The scale control technology developments have been driven by these perceived risks. Many of the technologies have already been tested within the North Sea. Furthermore, there are trials planned in the deep water fields of the Gulf of Mexico and West Africa.
An Approach to Mitigating Wellbore Solids Deposition
Authors: Kabir C. S. , Hasan A. R. , Lin D. , Wang X. 
Published: December 2007

AbstractTubular flow restrictions owing to solids deposition are serious oilfield problems. Solids normally originate from either asphaltic or paraffinic oil. Hydrates add another dimension to the problem when water production begins. Most solutions center on the use of aromatic solvents for asphaltenes and chemicals or heating for paraffins.In this study, we seek preventive measures to minimize solids deposition by altering characteristics of fluid flow in the wellbore. Knowledge of thermodynamic behavior of fluids and application of principles of fluid and heat flows constitute the essence of our approach. Specifically, we present a steady-state model that allows computation of wellbore pressure and temperature profiles for a hot-circulating fluid in case of parrafins. The same model is used to study the p-T behavior of asphaltic oil while circulating a cold fluid.A fluid-temperature model is also presented when intermittent or continuous injection of solvent is sought through a chemical-injection line. Both models are general in that flows in offshore wells can be handled rigorously.Computational results show that preserving energy of paraffinic oil is feasible by circulating hot fluid in the annulus and/or using insulation, thereby keeping solids in solution. The use of an unsteady-state flow model sheds light on the time available for well intervention before the onset of deposition. Similarly, cooling of fluids may help produce asphaltic oils under favorable conditions.
Automated Reservoir Model Selection in Well Test Interpretation
Authors: Güyagüler Baris , Horne Roland N. , Tauzin Eric 
Published: December 2007

Abstract
Technological achievements in the area of well testing, such as permanent downhole gauges, demand automated techniques to cope with the large amounts of data acquired. In such an application, the need to interpret large quantities of data with little human intervention suggests the desirability of automated model recognition. Also in some cases the characteristic behavior of the pressure or its derivative curves for specific models may be hidden behind noise or human bias may lead to the selection of an invalid or inappropriate model.
This paper demonstrates an approach based on Genetic Algorithm (GA) that is able to select the most probable reservoir model among a set of candidate models, consistent with a given set of pressure transient data. The type of reservoir model to be used is defined as a variable and is estimated together with the other unknown model parameters (permeability, skin, etc.). Several reservoir models are used simultaneously in the regression process. GA populations consist of individuals that represent parameters for different models. As the GA iterates, individuals that belong to the most likely reservoir model dominate the population, while less likely models become extinct. Since different models may require different numbers of parameters, the solution vectors have varying lengths. The GA is able to cope with such solution vectors of differing size. Information exchange (GA crossover operator) is allowed only between parameters that are physically related.
Alternatively, we illustrate the use of GA as a preprocessor for conventional gradient-based algorithms such as LevenbergMarquardt. When combined with the GA, the dependency of such conventional algorithms to the initial guess is reduced and the overall regression performance is improved. For automated interpretations where the model is already known this method allows to virtually eliminate the initial guess determination step.
Tests on real and synthetic pressure transient data indicated that the proposed method was able to select the correct reservoir model. The method revealed hidden implications of the pressure transient that may otherwise have been overlooked due to noise. As a preprocessor for more conventional nonlinear regression approaches, applying GA to a number of noisy pressure transient tests demonstrated that the method is robust and efficient.
Characterization of Fractures/Faults Network from Well Tests; Synergistic Approach
Authors: Al-Thawad Faisal , Bin-Akresh Saud , Al-Obaid Rashid 
Published: December 2007

Abstract
In this paper we demonstrate the successful identification of a new flow problem of an intersected natural fracture connected to (or near) a finite conductivity fault. In a previous paper, finite conductivity faults in connection with high permeability layers were identified in mature parts of Ghawar field(1).
Four field cases are presented in this paper; a slanted well intersecting a fracture, a well close to a finite conductivity fault and a combination of the two. In the latter case, two examples of a fracture behavior at early times and a finite conductivity fault behavior at late times were identified. Because of the complex nature of these flow problems, numerical simulation along with all available data was integrated including 3D seismic to match the pressure response.
Transient Dual Porosity Behavior for Horizontal Wells: Case Histories
Authors: Verga F. M. , Beretta E. 
Published: December 2007

AbstractOccurrence of bilinear flow regime in various geological situations has been discussed rather extensively in the literature. In particular, it was theoretically demonstrated that the bilinear flow regime can arise in the case of horizontal wells draining fractured reservoirs due to transient dual porosity behavior originating during the intermediate linear flow period. The bilinear flow regime can be identified by analysis of the well transient pressure response as the pressure derivative exhibits the characteristic quarter slope on the loglog diagnostic plot. However, the duration of the transient dual porosity behavior depends on the system geometry, namely location and length of the horizontal well and thickness of the producing layer, and on the permeability contrast which reportedly exists between the more conductive fractures and the feeding matrix. Three interesting case histories are presented in this paper where the pressure derivative response for horizontal wells drilled in different fractured reservoirs indicated the occurrence of the transient dual porosity behavior before that the linear flow, which is typical of horizontal wells in homogeneous reservoirs, was achieved. In agreement with the geological surveys it was interpreted that the bilinear flow was caused by two intersecting fracture systems showing a strong permeability contrast whereas the feeding action of the matrix, if any, could only be detected at a later time. In two cases clear evidence of pseudo steady state dual porosity behavior, indicated by the distinctive inflection in the derivative pressure response, was also observed, thus confirming the proposed well test interpretation. Several parametric analyses are also presented to define the geometrical and petrophysical conditions under which evidence of the bilinear flow regime can be expected.
Field Examples to Bridge the Gap Between Production Engineering and Reservoir Engineering
Authors: Su H-J. , Al-Rasheedi S. 
Published: December 2007

Abstract
Often time when a production engineer conducts a nodal analysis, he assumes a constant reservoir condition. Typically, a downhole shut-in static pressure will be taken as the reservoir pressure. In this work, we will demonstrate the importance of using reservoir simulation to model reservoir dynamics in conjunction with other production engineering tools.
The integration has helped us identify the cause for an extremely high skin generated from a short-term water injectivity test. Without reservoir modeling, we cannot be sure if the skin was from fine-particle plugging, or clay expansion, or wellbore debris accumulation. Interestingly, the build-up pressure derivatives were quite different prior to and after 1991. This discrepancy was explained by a partial blockage of one sand layer that was generated by an invading cement mixture during fire fighting after the Gulf war.
Another example shows use of production logging to solve a puzzle for a reservoir engineer. There is a vertical well and an expanding secondary gas cap has surrounded its upper portion. Its GOR value has been surprisingly low. The findings from production logging also help us characterize the geology around this well.
Using real examples, we show how to build synergy between reservoir engineers and production engineers. This work demonstrates the usefulness of reservoir simulation to help production engineers diagnose well operation problems.
A Newly Designed Electronic Memory Gauge Improves Reservoir Characterization
Authors: Azari M. , Fraser C. , Kool H. , Soliman M. Y. 
Published: December 2007

Abstract
This paper presents a new quartz electronic memory gauge that has been introduced to the oil industry. This gauge can record data with more precision than existing gauges, and thus, can establish more accurate flowing and shut-in pressure with higher resolution. In addition to describing the gauge design, this paper will also discuss the advantages of improved gauge resolution in the analysis of well test data and in determination of the hydrocarbons in place. The impact of using a higher resolution gauge on well testing is illustrated through analysis of field data.
Integrated Simulation of Reservoir, Gas Plant, and Economics for A Rich Gas Condensate Reservoir
Authors: Wang S. W. , Ringe D. P. , Gable M. M. , Staples D. J. 
Published: December 2007

Abstract
In the development of a rich gas condensate reservoir, a surface separator alone is usually not enough to condense all the heavy components from the produced well stream. A gas plant is required to extract the heavy components still remaining in the separator effluent gas. The operation can be further complicated by reinjecting the produced gas in order to control pressure decline rate and maximize condensate production. This work presents a method in reservoir simulation which significantly improves the history matching of condensate production and an algorithm which can be used to determine the concentration of individual components from the composition of pseudo-components. The achievements of this study include (1) the correct simulation of the composition and quantity of reinjected gas and wet inlet gas to gas plant, (2) the correct simulation of C3 spike due to lean oil absorption unit, (3) a workable algorithm to bridge reservoir and gas plant simulation at each time step, (4) rapid turnover time for each scenario by integrating reservoir, gas plant and economics into a single loop as opposed to three separate, unconnected simulation studies.
Reservoir Modeling - Prudhoe Bay Sadlerochit
Authors: van Poollen H.K. 
Published: December 2007

Introduction
The basic objective of this study was to evaluate the relative oil recovery potential of the Sadlerochit Reservoir at Prudhoe Bay under a number of different operating conditions. The reservoir was modeled in cross section, using a six-layered, two-dimensional, three-phase mathematical fluid-flow simulator. This work was preceded by a published volumetric study and other preceded by a published volumetric study and other independent, confidential studies based on proprietary information which were designed to proprietary information which were designed to develop the best basic data with which to describe initial reservoir geometry, volume, fluid and energy conditions.

BOUNDARY CONDITIONS
General boundary conditions were established such that the following basic cases could be evaluated and compared:Depletion drive with gas cap expansion and gas reinjection into the gas cap from the start of producing operations—no aquifer. producing operations—no aquifer.Depletion drive with gas cap expansion and gas reinjection, supplemented by a moderate-sized aquifer.Depletion drive with gas cap expansion, gas reinjection and a moderate-sized aquifer supplemented by water injection.All of the preceding cases were also considered with gas cap sales of 2 MMMSCF/D, and some cases with 3 MMMSCF/D, and 4 MMMSCF/D.Special cases, all with aquifer, water injection and gas cap sales, where certain operating limits were changed:Five well groups were recompleted and GOR limits increased to 25,000 SCF/STB on allwells after 13 years (GOR limit otherwise was 15,000 SCF/STB and WOR limit was3 STB/STB for all cases).Two more well groups were added near the gas-oil contact after 14.75 years to control the potential loss of oil into the gas cap.Five of the above special cases had gas sales delayed.A range of maximum sustained oil-producing rates of 1.2 MMSTB/D, 1.6 MMSTB/D and 1.8 MMSTB/D was set for most of the preceding cases. All runs were scheduled to produce at 0.6 MMSTB/D for the first 3 months, 1.4 MMSTB/D for the next 12 months, and then at one of the above maximum rates until the start of decline.
Fast and Robust Algorithm for Compositional Modeling: Part II - Two-Phase Flash Computations
Authors: Pan Huanquan , Firoozabadi Abbas 
Published: December 2007

Abstract
In Part I of our study, stability analysis testing in the reduced space was formulated and its robustness and efficiency in comparison to the conventional approach was explored. In this paper, we present formulations including: 1) direct solution of the non-linear equations, and 2) minimization of Gibbs free energy for two-phase flash computations in the reduced space. We use various algorithms including the successive substitution (SS), Newton's method, globally-convergent modifications of Newton's method (line searches and trust region), and the dominant eigenvalue method (DEM) for direct solution of the non-linear equations defining two-phase flash and the minimization of Gibbs free energy. We also suggest a criterion based on the tangent-plane-distance (TPD) for the initialization from the equilibrium ratios. The proposed criterion has a significant effect on reducing the number of iterations.
The results from various algorithms reveal that the direct solution of the non-linear equations in the reduced space combined with the use of the TPD criterion for initialization in the combined SS and Newton's method can make flash computations extremely efficient. The efficiency and robustness of flash computations in the critical region are especially remarkable.
Single-Well Waterflood Strategy for Accelerating Oil Recovery
Authors: Guerithault Raphael , Ehlig-Economides Christine A. 
Published: December 2007

Abstract
Conventional primary production addresses from 3% (expansion of undersaturated oil) to about 15% (solution drive) of the original oil in place. An active water or gas cap drive may boost recovery significantly under ideal conditions, but otherwise pressure maintenance via water or gas injection is required. Simulations over a wide range of reservoir and fluid properties demonstrate that waterflooding from the start of production and maintaining pressure via reinjection of produced water can yield a target of 50% recovery of the oil in place in less than 5 years. The proposed single well with laterally parallel segmented horizontal branches accommodates water injection in one branch and production from the other branch with a downhole separation and reinjection system designed to reinject all produced water for up to 90% water cut in the producing branch.
A simple procedure provides the optimal length of the laterals and the optimal separation between them to achieve the target recovery factor, given the reservoir and fluid properties. When closer spacing is needed to achieve sufficient pressure support for the producer or to ensure sufficient connectivity between the wells, longer laterals can be drilled to reach the same total in-place oil volume. The procedure uses previously established formulas for line drive waterflood performance adjusted for vertical to horizontal permeability anisotropy.
The single-well waterflood avoids the need to lift and reinject produced water and accelerates the pore volume throughput, thus enabling the constant oil production rate (and equal surface water injection rate) characteristic of p-mode production. Also, the resultant constant reservoir pressure provides steady state conditions in the surface facility, greatly reduced risk of reservoir compaction or subsidence, and virtually no impact on the surrounding reservoir. Viability of the economics is easily demonstrated with net present value computations.
Multilateral Waterflood Development of a Low-Permeability Carbonate Reservoir
Authors: Bigno Y. , Al-Bahry A. , Melanson D. D. , Al-Hasani S. , Senger J. Ch. , Henning R. 
Published: December 2007

Abstract
The Shuaiba limestone reservoir of the Saih Rawl field (Oman) is a nearly unfaulted, low-relief structure of large areal extent. Permeability is matrix-dominated and relatively low (1 to 10 mD). The reservoir contains approximately 90 106 m3 of light oil (35 API) in column heights of typically 15 to 30 m.
Economical production only started in the early 1990's, 20 years after field discovery, when horizontal well technology could be effectively introduced. Today, multi-lateral wells of up to 7 legs are used in a pattern water-flood development. Total open-hole lengths drilled in the reservoir have reached 11 km for a single well. To date, 166 km of producing and 107 km of injecting open-hole have been drilled, representing 167 horizontal legs, and yielding an oil production level of up to 9,000 m3/d (60,000 bbl/d). The original producer to injector leg spacing of 250 m has gradually been decreased to 60 m and still fits the economic criteria.
In 2000–2001, a field development review was carried out to identify further development opportunities, both for the short and long term. A series of new reservoir management tools were put in place to predict the response of the reservoir to various development options. A pilot area was defined in order to test these concepts and perform extensive data gathering. Finally, new lab and feasibility studies were initiated. As a result from this review, a portfolio of short and medium term activities was identified, including infill drilling to 40 m spacing, and drilling additional injection legs in existing injectors. Also, upsides for developing the flank areas of the field (sub-15 m oil columns) were identified. Later, fishbone legs drilling and reversing water injection into existing producers will be piloted, while sweep optimization methods such as water shut-off and re-stimulation are envisaged to target recovery factors in excess of 50%.