bluuebunny/crossref_metadata_2025_split huggingface dataset:
Gravity Methods: Useful Techniques for Reservoir Surveillance
Authors: Brady J. L. , Wolcott D. S. , Aiken C. L. V. 
Published: December 2007

AbstractUnderstanding the movement of gas in oil reservoirs is important because premature breakthrough or high gas-oil ratios significantly increase costs and can reduce ultimate recovery. The Prudhoe Bay and Kuparuk River oil fields, located on the North Slope of Alaska, have an expanding gas cap and a gas storage area, respectively. Significant gas movement in both reservoirs has occurred, since discovery, and the vertical and areal extent are not as well defined as desired. The current methods of monitoring are expensive and increasingly less reliable because of well conditions.In a search for better methods to monitor gas movement, borehole and surface gravity techniques were identified. The Borehole Gravity Meter (BHGM), because of its large radius of investigation, can predict the true gas-oil contact, irrespective of a localized gas cone and other near wellbore completion problems. Bypassed lenses of oil and intervals of gas under running oil can be identified. The data from the BHGM can provide the vertical distribution of gas and oil at a well. To better understand the areal distribution of gas, high resolution surface gravity data can potentially be used. As the gas cap propagates outward and/or downward, a negative gravity anomaly is created due to the displacement of oil by gas.The results show that significant gravity anomalies have occurred in the Prudhoe Bay and Kuparuk River oil fields due to gas replacing oil. The gravity anomalies can be measured with the borehole gravity and in certain situations with surface gravity instruments. New surveying techniques are needed to obtain increased vertical and lateral resolution for reservoirs buried as deep as the North Slope fields. Global Positioning Systems (GPS) is an economically viable method for obtaining accurate surface positions for locating surface gravity stations. Surface gravity data resolution can be improved further by stripping and downward continuation. The newly developed elevator sonde for the borehole gravity meter, may significantly improve the vertical resolution of the tool in deep deviated wells.Additional developments to improve deviation and size limitations of the BHGM, data acquisition and processing of surface gravity, and testing of GPS in Arctic latitudes are required. Plans to field test these techniques and provide data to design new techniques and tools are on going.
Program for Improving Multiphase Flow Slug Force Resistance at Kuparuk River Unit Processing Facilities
Authors: Santana B. W. , Fetzner D. J. , Edwards N. W. , Haupt R. W. 
Published: December 2007

Abstract
Multi-phase slug flow forces in pipelines at the Kuparuk production facilities have caused fatigue damage to piping components and vessel nozzles. A program was implemented to modify the existing inlet systems to accommodate slug forces for current and forecast flow conditions. Data acquisition systems were installed to quantify the effect of modifications on vessel stresses. The systems are also providing justification to avoid more costly modifications while allowing continuous improvement of operating parameters in the field.
Oil Recovery Simulation for Heterogeneous Reservoirs
Authors: Myerson A. S. , Izmailov A. F. , Kessel A. R. 
Published: December 2007

Abstract
Description of the oil recovery process implies creation of an adequate simulation model. One of the such models, the Dynamic Invasion Percolation with Trapping (DIPT) model, has been recently developed [1, 2]. This model is based on two independent steps.
The first step is to describe the oil reservoir saturated and/or unsaturated porous media in terms of the integer lattice models. In these models the lattice sites and bonds are identified with pores and capillary channels, respectively. It was suggested in [1,2] to describe n possible different states (empty, filled with displacing fluid or displaced one, etc.) of each lattice site j (j ⊆ [1, N]) in terms of the time-dependent n-component spinor functions χjm(j)(t), where N is the total number of lattice sites and m(j) ⊆ [l, n]. In such an approach the time-dependent state function ψ(t) of the entire lattice modelling oil reservoir porous medium can be introduced as the following direct product: (1)Ψ(t)=∏j=1N⊗χjm(j)(t).
The second step is to describe evolution of the oil reservoir subjected to the recovery process. It was done within the DIPT model. In this model it was suggested to describe evolution of the oil reservoir state function ψ(t) with the help of the following Schrodinger-like equation: (2)∂Ψ∂t=τH Ψ(t),
The Use of Optimal Control Technique To Validate Reservoir Simulation Results
Authors: Elemo R. O. , Lawal A. S. 
Published: December 2007

ABSTRACT
The advent of fast digital computer has made numerical modeling of petroleum reservoirs very attractive, starting with a landmark paper published in 1953 by G.H. Bruce, et al. Reservoir simulation, a major numerical modeling technique, has now become an important tool used to study the performance of oil and gas reservoirs of various complexity where several variables are involved, and therefore, analytical solution may not be appropriate and/or closed form solution is not feasible. A number of sources of error in reservoir simulation application has been identified and documented in literature. One major source of error is frequent use of inaccurate reservoir description data. Therefore, model validation and calibration, meant to ascertain the correctness of the simulator and the applied description data, are essential parts of reservoir performance numerical modeling. Model validation and calibration are usually done by history matching of the field performance data and simulator calculated performance responses. In the last couple of decades, there has been considerable interest in the development of automatic history matching algorithms. Automatic history matching is preferred to the traditional trial-and-error approaches despite the fact that the automatic routines require some additional iterative optimization routines to the basic simulator because the investment of additional optimization code development time and computational CPU time is worth the effort.
Endurance Testing Begins Where API 6A 16th Edition Appendix F Ends
Authors: Dach A. J. , Nordeen Merle 
Published: December 2007

Abstract
AN OVERVIEW OF API SPEC 6A, APPENDIX F
API Spec 6A has undergone extensive revisions to become a more widely accepted specification worldwide. API 6A is no longer a dimensional specification. The 15th Edition of API 6A, which was effective 4/86, dealt in detail with quality levels of the iron used to manufacture API 6A components. The 16th Edition, which was effective 4/89, dealt in detail with quality and performance of API 6A metallic components, seals and sealing materials. The new API 6A will now make it possible for a user to spec in the cleanliness of the steel and the performance requirements of the seal required to meet the actual intended service conditions which include pressure (oil or gas), produced well fluids, actual well temperature and production variables such as inhibitors, acidizers, etc.
Performance testing for valves currently identified in API Spec 6A was developed by surveying users of API equipment A task team, consisted of 56 members, both users and manufacturers, was set up to analyze this data. These team members were mostly technical in background. After two years of technical discussions analyzing data and test programs, the team agreed to the performance testing shown in Appendix F of API 6A. The testing outlined for valves represents what the average product would endure in its field life. The three pressure temperature cycles outlined for wellhead seals, hangers, etc. represent a tortuous path that, if endured by a seal, it would continue to perform for its expected life.
DRIVING FORCES BEHIND ENDURANCE TESTING
Prior to the 15th Edition of API Spec 6A, many users of 6A products worldwide had identified weaknesses in Spec 6A. North Sea users were requiring equipment which basically met PSL 3 as now defined in Spec 6A. The MMS required SPPE surface safety valves be used on all wells drilled in Outer Continental Shelf waters. The requirements for this equipment exceeded PSL 2 and PR 1 as now defined in Spec 6A. Several major worldwide users of 6A equipment had developed internal specifications which outlined requirements for equipment which exceeded PSL4 and PR2 as now defined in Spec 6A.
Desktop Computer Application for Quantifying Cycle Wells Performance
Authors: Smith Matthew , Lawal A. S. 
Published: December 2007

Abstract
Synopsis
The expert system was developed for the Prudhoe Reservoir Engineering group to query the effectiveness of gas utilization on individual wells basis. It analyzes welltest and production data within the Production Database (PDB) to obtain an historical perspective of oil production and the decline parameter of a given well or group of wells in a pad/ or drill site. Historical production trends are monitored by well to identify candidates for well cycling, workover or shut-in. By specifying a date range for the required production data, an Excel-compatible spreadsheet and associated graphs are produced in real-time.
Description
Cycle Well program developed from expert system has recently been used in the Gravity Drainage regions and up-structure areas of the Prudhoe Bay Field (PBU) to optimize production strategy of high GOR wells (&gt; 5000 scf/bbl). The program consists of strategies for intermittently producing high GOR wells by optimizing the flowing and shut-in schedules of the individual wells (details of the schedules are provided in SPE paper No. 26091 by Easley and Lawal). The program provides information for cutting gas allocation to the individual wells, thereby converting cycle wells into continuous producers. The use of the program with the historical performance of individual wells and available geologic data provides a means of enhancing oil production from high GOR wells.
Posters Display
The posters are developed from the reservoir mechanics of high GOR wells using integrated knowledge of Reservoir and Production Engineering coupled with expert system programmers from BP Computing community. The posters provide algorithms for displaying information about the performance of individual wells using the production database. The information display include oil rates, gas rates, GOR, cycle periods, measure of decline parameters, down time periods. The technique is applicable to the wells in a pad/ or drill site or the wells feeding into a gathering center or flow station; it can also be tailored to selected group of wells.
Petrographie Image Analysis: An Effective Technology for Delineating Reservoir Quality
Authors: Gies R. M. , McGovern Jon 
Published: December 2007

Abstract
Petrographie Image Analysis (PIA) is an emerging technology used to estimate the properties of pore systems that occur worldwide in sandstone, carbonate and conglomerate reservoir rock samples. It provides quantitative evaluations from standard core plugs as well as from material unsuitable for conventional core analysis such as core rubble and drill cuttings. PIA technology also supplements routine core analysis by estimating other parameters like the specific pore size interval that regulates fluid flow.
The method described here is based on a simulated capillary pressure curve. It has been used routinely to estimate pore and pore-throat size distributions, porosity, permeability, air-mercuiy capillary pressure, irreducible water saturation, effective porosity, microporosity, seal capacity, and the minimum saturation of the non-wetting phase at which it becomes mobile throughout the pore system. These and other new relationships being developed and tested can be mapped to help delineate trends in reservoir quality.
PIA procedures and relationships are discussed and illustrated with an example application from a large gas reservoir in the Western Canadian Sedimentary Basin.
New Insights in the Formulation of Porous Media Mass and Momentum Equations
Authors: Civan Faruk , Evans R. D. 
Published: December 2007

ABSTRACT
New equations for porous media mass and momentum conservation for variable fluid and porous media properties are derived by representative volume averaging of the microscopic laws. The new mass conservation equation contains an extra term interpreted as mass transfer by spatial dispersion in porous media. The new momentum conservation equation contains only one empirical parameter, referred to as an apparent permeability. It is shown that the Klinkenberg and Forchheimer equations can be derived readily from the apparent permeability concept. Therefore, it is concluded that future research should be devoted to developing correlations for the apparent permeability rather than an absolute permeability, inertia resistance coefficient, and other parameters that the special equations Darcy, Forchheimer, and others may include. It is also shown that apparent permeability is a function of the porous media Reynolds number which implicitly includes the information about the fluid conditions through density, viscosity, and flow rate, and the information about the porous media properties through the use of an apparent pore size diameter concept. The present study, thus, leads to new insights into the mathematical description of the flow behavior in porous media.
CO2 Foam Slurry Friction Correlations
Authors: Kenyon D. E. 
Published: December 2007

Abstract
An analysis of turbulent fluid friction was made for data of vertical flow of C02-foam slurries. These data were obtained during a fracture stimulation in a uniquely-instrumented, 3.5-inch tubing string. Data were culled to steady state for each C02 cut, gel concentration, sand loading, and rate. Friction gradients were computed and a new friction correlation was developed. The correlation uses the friction factor concept for high speed, single phase flow by defining appropriate mixture density, viscosity, and Reynolds number from foam slurry properties.
Analysis of Abnormally High Fracture Treating Pressures Caused by Complex Fracture Growth
Authors: Davidson B. M. , Saunders B. F. , Robinson B. M. , Holditch S. A. 
Published: December 2007

ABSTRACT
INTRODUCTION
The Gas Research Institute's (GRI) fourth Staged Field Experiment (SFE No. 4) well was drilled as part of a field-based research program that has been conducted in the Frontier formation of southwest Wyoming. During this experiment, data were collected from whole cores, multiple sets of openhole logs, in-situ stress measurements, microseismic surveys, and multiple injection (mini-frac) tests.1 These comprehensive data sets have been used to fully describe the Frontier sandstone. This paper summarizes the analysis of abnormally high fracture treating pressures that were observed on SFE No. 4.
Over the past two decades, the analysis of the net or excess pressure has become an important diagnostic tool for the petroleum engineer to evaluate hydraulic fracture treatments. The technique was introduced to the industry by Nolte and Smith2 and has been used in many situations to diagnose fracture growth patterns. Net pressure analysis can also be used to categorize formation types based on their net pressure response.3 Abnormally high fracture pressures encountered in certain formations have also been evaluated with this method4
It was evident from the initial injection tests on SFE No. 4 that the injection pressure was noticeably higher than other wells in the area.5-9 Due to this high injection pressure, a series of diagnostic injection tests was developed to evaluate the cause of the high pressure. These tests indicated the high injection pressures were caused in part by high near wellbore friction. We also saw evidence of high net pressures in the fracture, indicating that multiple fractures were propagating simultaneously.
Electronic Gas Management: An Integrated Approach
Authors: Halliwell K. A. 
Published: December 2007

ABSTRACT
To support the complex operation of a large gas transmission system, information must move rapidly and accurately within NOVA and between NOVA and its business partners. With the implementation and integration of systems to perform pipeline control (SCADA), commodity management, electronic flow measurement (EFM), and electronic data interchange (EDI), this goal is being achieved.
This paper will follow a typical process from a customer's electronic request for gas, through the commodity management system for contractual and operational checks, to the issue of a change in flow, the control and measurement of that flow through the SC AD A and EFM components, back through the commodity management system, and through to the communication of the transported commodity totals back to the customer.
Process Design Integration: A New Optimized Approach That Will Facilitate Gas Development Projects for Nigeria
Authors: Ofoh E. P. 
Published: December 2007

Abstract
Nigeria is blessed with Natural gas reserves whose abundance is estimated in the range 100-300 trillion cubic feet. It is, perhaps, the most wasted energy resource in Nigeria: In 1970, there was no gas processing plant in Nigeria and as such about 99 percent of all gas produced was flared. In 1979, the Nigerian government filed a directive that required the multinationals to find utilization for gas reserves and all gas produced. The goal was to reduce energy waste and environmental pollution. As an alternative to the above decree the multinationals were required to pay penalties for all gas wasted. Despite this decree, and encouraged by still lack of facilities, gas flaring continued with the Operators under great regulatory and economic pressures. A Joint Venture between government and the multinations agreed to finance gas projects which would be founded on sound engineering basis. An integrated process design is a cost-effective conceptual engineering in which process and utility systems are carried out in parallels and with the cooperation of all subgroups. This integrated technology is expected to put both the conceptual and the detailed designs of the fast lane and thus alleviate the fears of the Nigerian clients.
The other advantages of the integrated process design over the conventional design are:–Consistent optimization of the entire design is now possible and less complex.–Primary process and utility equipment set up which constitute about 90 percent of the total capital investment are now made early before final construction is embarked upon.–Work activities relating to subsystems can now be done cooperatively and in parallel by the use of softwares which can transfer final simulation output into subsystem spreadsheet programs for quick updates of results.–The integrated process, founded on sound engineering judgement and consistent with well defined energy efficiency has an advantage of reducing the overall construction schedule.
A detailed account of this new process and its future on worldwide projects will be outlined. The effect of reimbursable arrangement will be mentioned.
Risk-Based Considerations in Developing Optimum Hydrotest Strategies
Authors: Leis B. N. , Rahman Sharif 
Published: December 2007

ABSTRACT
As pipelines age, a flaw population that varies initially along the pipeline can advance in size and number. Analysis of the serviceability of pipelines based on either in-line inspection or hydrotesting can lead to overly conservative decisions or an excessive risk of failure when the random nature of this population and the pipeline's properties are represented by a "typical" flaw and "average" properties. It follows that decisions on serviceability should reflect the random nature of the variables involved or be justified by demonstrating that the uncertainty in these parameters does not adversely effect cost and safety.
This paper explores the significance of the random variables related to serviceability in pipelines. This study is made under the assumption that continuing serviceability is based on the use of hydrotesting. Results generated via probabilistic analysis form the basis for the discussion of risk and safety and the significance of the random variables. This same technology could be used in (1) risk and safety assessments associated with pipeline operating decisions, (2) designing hydrotests and choosing their frequency to ensure continued safe operation of the line, and (3) assessing the operating and safety implications for flaw populations characterized by in-line inspection.
Identification and Potential Treatment of Near-Wellbore Formation Damage in a Horizontal Gas Well
Authors: Jamaluddin A. K. M. , Vandamme L. M. , McGuffin R. G. 
Published: December 2007

Summary
This paper presents the results of a study carried out to identify near-wellbore formation damage in horizontal wells. Formation damage occurs when pore throats are constricted by clay swelling upon contact with incompatible fluids, by clay migration or by plugging with drill solids and mud products. Relative permeability effects can also cause water/condensate blocking and subsequent reduction in loadfluid recovery and productivity.
Extensive laboratory experiments were carried out on cores from wells offsetting four poorly producing horizontal wells in a gas-bearing formation. The results indicated that clay-related near-wellbore formation damage was the primary cause of the low productivity from these horizontal wells. Results from further laboratory investigation indicated that the formation damage could be remedied using an oxidizing material (e.g., hydrogen peroxide).
Based on these laboratory results, a field test was carried out to treat the near-wellbore formation damage using a mixture of oxidizing fluid and acid. The results of this field test are also presented in this paper.
Isotope Analyses of Gases in Gas Field and Gas Storage Operations
Authors: Schoell Martin , Jenden P. D. , Beeunas M. A. , Coleman D. D. 
Published: December 2007

ABSTRACT
Natural gases vary in chemical and isotope composition as a function of their formation and migration history. Compositional and isotopic variations are often caused by mixing of two or more compositionally and isotopically different gases. Isotopic properties in gases can be used to determine the mixing ratio of the two endmembers and/or calculate the composition of the endmembers from different mixing ratios. The variations of isotopic properties of gases within a continuous reservoir are generally small but can be significant between fault blocks of one reservoir or between unconnected but closely stacked reservoirs. These inter-reservoir variations can be utilized to help solve many problems occurring during gas field development and operation:

Reservoir Identification:
Gases within a single reservoir are very similar, but non-communicating reservoirs can often be differentiated through isotopic differences in their gases. Isotope analyses of gases could be helpful in such cases to identify the production zone in new completions.

Reservoir Compartmentalhation and Fault Block Mapping:
Isotopic signatures of gases in faulted reservoirs with completions in different fault blocks can be used for better identification of sealing faults and subdivision of drainage compartments.

Reservoir Allocation:
Isotope analyses in commingled production could be used to allocate contributions from individual sands if isotopic differences exist between the gases from the contributing reservoirs.

Gas Storage:
Gas storage fields provide excellent "laboratories" for demonstrating the effects of mixing gases of different compositions. Examples are given which demonstrate the use of chemical and isotopic analyses to calculate mixing ratios of storage gas and native gas.

Identification of Gas Seeps:
Movement of natural gas from reservoirs to the surface may change the concentration of gas components, but the isotopic composition remains mostly unaltered (isotope changes through oxidation can be recognized through special isotopic anomalies in compound patterns). Isotope analyses can, therefore, help identify the source of surface gas leaks.