bluuebunny/crossref_metadata_2025 huggingface dataset:
Mathematical Modeling in the Coyanosa Field
Authors: Wallen D.A. , Raleigh J.T. , Distefano C.R.
Published: December 2007

American Institute of Mining, Metallurgical and Petroleum Engineers, Inc.

A study of the Coyanosa, Ellenburger and Devonian reservoirs was made using a two-dimensional, single phase, unsteady-state computer program. The model was made to fit the general physical conditions thought to exist in the reservoir under study and then adjusted by a history-matching technique.

The matching technique is discussed with an example of how the reservoir parameters were manipulated to achieve a match. An example is given of the use of the adjusted reservoir model as a tool for investigating the effects of various allowable rates on availability of gas over periods of several years.

The authors believe the approach outlined in this paper to be of considerable value in availability projections and reserve determinations. Use of the model allows projections to be made on the basis of individual well performance that includes interaction and performance that includes interaction and changing drainage patterns of all wells in the reservoir.

Introduction

This paper presents a discussion of a history-matching method using a mathematical reservoir model for projection of gas reserves and availability, and the result of a study to apply this method to the Coyanosa field of West Texas. This field was chosen for the study because it is in a newly developing area, and because it is an important new source of supply in the Permian Basin.

Pressure data resulting from the short production history of the two deepest Coyanosa production history of the two deepest Coyanosa reservoirs indicated that actual reserves were less than the originally accepted reserves, which had been based on volumetric estimates.

Therefore, an attempt was made to simulate the Devonian and Ellenburger reservoirs using a two-dimensional, unsteady-state, single phase model. The procedure followed was to try to force the computer model to match the appropriate cumulative production information by wells and the stabilized pressures obtained from a fieldwide shut-in period in May, 1967, and then to use the model for forecasting reservoir performance to depletion. This forecast estimate performance to depletion. This forecast estimate is thought to be more reliable than estimates arrived at by conventional methods for approximating availability of gas and individual well recoverable reserves.

DISCUSSION OF METHOD

To approximate the physical reservoir as a mathematical model, certain steps must be followed.

The reservoir isopach map must be overlaid with a grid base and a grid size and location must be selected that will provide the well interference and drainage information necessary, keep computer time to a minimum, and minimize distances between well locations and the nearest grid intersection. The reservoir boundary must be approximated with grid lines knowing that, in this model, the mathematical boundary is one half grid size outside the drawn boundary [Fig. 1]. Each well must be located with respect to the grid system and a boundary thickness estimated.
Luna Gas Field: A Development Optimization Project of a Very Heterogeneous Reservoir
Authors: Erba M. , Descalzi C. , Sguzzini P.
Published: December 2007

The topic of the paper is the case study of an Italian gas field, characterized by highly heterogeneous communication schemes, which has been producing for fifteen years through fifteen wells.

The study was aimed at the identification of production mechanisms in order to optimize the field development and the gas recovery.

The crux was the detailed reconstruction of the reservoir internal structure. This could be obtained only through a methodology whose peculiarity is a close cooperation and integration between geophysicists, sedimentologists, petro-physicists and reservoir engineers.

The numerical discretization of the geological model proved to be particularly complex and was carried out through a very refined and composite grid.

Unfortunately, the dynamical simulation was partially jeopardized mainly due to the paucity and poor reliability of the available dynamical data, a basic problem for Luna field study.

The resulting detailed numerical model of the reservoir internal structure however represents a reliable dynamical and static data base easily updatable with future data.
The Installation, Commissioning and Operation of Subsea Emergency Shutdown Valves in the Tartan Field
Authors: Dawes A.
Published: December 2007

This paper describes the project to install subsea emergency shutdown valves on the existing Texaco Tartan Platform oil and gas export pipelines located in the North Sea. A brief summary of operational experience of these emergency systems is included.

As a result of the Piper Alpha disaster the Tartan oil and gas export pipelines were shutdown and decommissioned until reinstatement by Occidental of the subsea pipeline systems around the Piper location. Texaco decided to enhance the safety of Tartan Platform by installing subsea emergency shutdown valves on these pipelines during this shutdown period.

These valve systems were successfully designed, procured and installed to meet the reinstatement schedule and by October 1990 will have been in service for over 18 months.
Subsea Barrier Valves for Esmond and Ravenspurn North
Authors: Luedtke R. C. , Pallot J.
Published: December 2007

It is now normal practice to evaluate all pipelines, both new and existing, to determine if subsea valves would provide a safety benefit. Hamilton Brothers having performed this evaluation in 1988, concluded that for two of their large diameter, long length, product export lines, subsea barrier valves would significantly enhance platform safety.

The two export pipelines are connected to three platforms and they each had different priorities and constraints. The Esmond platform and its pipeline were operational and a complete retrofit system was required. The Ravenspurn North platform and its pipeline were new. Cleeton was an operating platform, but the pipeline was new.

The decisions taken during design were sometimes the same, but at other times very different. This paper describes the Projects with special emphasis on the differences between them.
Anomalies in Interpretation Of Reservoir Pressure Surveys
Authors: Cline W.B.
Published: December 2007

American Institute of Mining, Metallurgical and Petroleum Engineers Inc.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers Office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

The ultimate implications of bottom-hole pressure data interpretation rarely can be pressure data interpretation rarely can be foreseen in their entirety by the wellsite engineers originally developing those data. This situation is particularly critical in remote area exploration programs where original evaluation procedures are extremely expensive and crucial decisions regarding the future of large areas often depend on a limited quantity of data from very few wells.

This paper illustrates, by a series of examples, that formation pressure surveys may be taken too much for granted and that their contribution to evaluation decisions often are not fully appreciated.

No amount of rigorous mathematical treatment of pressure survey data can compensate for detailed planning and strict attention to the characteristics likely to lead to costly misinterpretation.

Introduction

Considerable attention has been devoted to the application and interpretation of reservoir pressure surveys in advanced oil and gas field pressure surveys in advanced oil and gas field primary and secondary development programs, primary and secondary development programs, while relatively minor importance has been attached to the benefits to be derived from these data in exploration efforts. Similarly, it is often only after field or reservoir development has progressed well beyond the discovery stage that the true value of such basic information is appreciated. It is at this late stage that pressure data, which could have been conclusively obtained during preliminary evaluation, may be found to be unreliable preliminary evaluation, may be found to be unreliable or even unavailable in any form.

This problem involving costly unreliable and/or misleading data may result largely from the fact that the development reservoir engineer often is divorced from the exploration phase, and does not become involved until such phase, and does not become involved until such time as a discovery has been classified as a development project.

ACCURACY OF DRILLSTEM TEST PRESSURE MEASUREMENTS PRESSURE MEASUREMENTS Consider the countless cases where the DST pressure data, especially initial shut-in pressure data, especially initial shut-in pressures, are used ultimately as vital basic pressures, are used ultimately as vital basic data for reservoir evaluation. The care taken in obtaining DST data of maximum accuracy often is appropriate only for qualitative analysis.
Indirect Evaluation of Fundamental Data for a Fractured Water-Drive Oil Reservoir.
Authors: Van Golf Racht T. , Peytchev Y.
Published: December 2007

American Institute of Mining, Metallurgical and Petroleum Engineers Inc.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers Office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Analysing the production mechanism and the energy of a fractured bottom water-drive reservoir a new method of future forecast was developed.

The basic idea was to build a model which takes into consideration the properties of an important number of cores, and dividing them in classes of different permeability. According to reservoir rate, a part of the classes will behave as macrofractures and another as microfractures, and consequently a rate-recovery relationship could be evaluated A model-reservoir relationship was proposed, so that the rate decline of model considered as maximum allowable gravity rate could be correlated with the reservoir registrated rates obtained in gravity-drainage conditions.

Based on this relationship and on trial and error Calculation procedure, the future performance could procedure, the future performance could be conveniently evaluated.

Introduction

A fracture is constituted by a considerable number of coarses and fine channels in a chaotic intercommunication.
A Knowledge Based Approach to Matrix Stimulation
Authors: Matteini L. , Cosenza G. , Paccaloni G. , Beranger A.
Published: December 2007

The paper presents an innovative approach to the development of a knowledge-based system aimed at support matrix stimulation design.

The basic role played by preliminary context evaluation is enhanced. Context evaluation involves assessing whether or not the stimulation must be carried out, through technical-economical feasibility analysis and risk assessment.

A conceptual model and a system architecture have been specifically defined for this domain, allowing fast and expressive system prototyping.

Extensive exemplifications of system reasoning performances are provided.
Production From Heavy Gas Condensate Reservoirs
Authors: Cvetkovic B. , Economides M. J. , Omrcen B. , Longaric B.
Published: December 2007

Heavy gas condensate reservoirs (γ > 0.75) present interesting challenges in their study, production and reservoir management. Simulation and history matching are often hindered by the lack of appropriate PVT properties. Furthermore, it is well established that they experience hysteresis effects following a shut-in. Remedial action is cumbersome but possible. This work presents a simulation of the behavior of both lean and heavy (rich) gas condensate reservoirs, shows radial liquid profiles for various flowing bottomhole pressures (compared with a phase diagram), demonstrates degree of gas relative permeability reduction and explains the hysteresis effect. Lean gas injection is a remedial action, reducing the near-wellbore liquid saturation. The study shows that the degree of the adverse gas relative permeability reduction can be minimized or tempered by the appropriate choice of the flowing bottomhole pressure, ie., production can be optimized.
The Haven "A" Development: The First Move of the First Tripod Tower Platform
Authors: Thompson J. M. , van der Graaf J. G.
Published: December 2007

The first T.T.P. was installed in July 1986 for Unocal Netherlands, as the Helder ‘B‘ platform.1 In June 1989 it was removed from its location, returned to an onshore fabrication facility for refurbishment, modifications and recertification and reinstalled for the development of the small Haven oil field in September 1989.

Development aspects of the Haven field are reviewed, together with the abandonment of Helder ‘B’. Structural design and modifications are discussed together with considerations for an unmanned platform, particularly in relation to reuse and extended life. The application of variable speed drives (V.S.D.'s) for control of downhole pumps on a remote facility are discussed, together with control from the Helder ‘A’ platform.

Production from the field commenced 15 November 1989 and the second horizontal well of the two well development was completed 3 December 1989. The reusability of the structure is evaluated in relation to the original design concept and the development planning for a single season completion is discussed.
Reversible In-Situ Gelation by the Change of pH Within the Rock
Authors: Vossoughi S. , Putz A.
Published: December 2007

Further experimental investigation was undertaken to elucidate the mechanism involved in a new in situ gelation process. In this process a newly discovered bio-polymer produced by Cellulomonas Flavigena strain KU is used. The process is different from the more commonly known in situ gelation based on crosslinking of polymer molecules with heavy metal ions. The difference lies in the inherent physical property of the polymer that its physical state of solution changes to the state of gel by reducing the pH of its alkaline solution. More importantly, the gelation process is reversible. That is, transition from the gel state to the solution state and vice versa can be repeated by increasing or decreasing the pH of the solution.

The experimental investigation aimed at answering two fundamental questions:

How selective and how uniform permeability reduction can be achieved within the core? How reversible is the permeability reduction induced within the core?

Experiments were performed in sand packs composed of two and three 10 cm long cells separated from the inlet face by an additional 2 cm long segment. Various injection schemes were tested while the pressure drop across each cell was monitored.

High degree of permeability reduction in the order of 100 to 6000 was achieved along the entire length of the sand pack. It was also possible to restore the initial permeability of the sand pack by injecting sodium hydroxide solution.

Creation of a layer of gel at the interface which is redissolved and re-gelled and which possibly moves in the direction of the flow path was considered a possible mechanism behind the uniform permeability reduction along the sand pack
Characterization of Tar From a Carbonate Reservoir in Saudi Arabia: Part I—Chemical Aspect
Authors: Harouaka A. S. , Asar H. K. , Al-Arfaj A. A. , Al-Husaini A. H. , Nofal W. A.
Published: December 2007

Tar mats are extra heavy oil zones sandwiched between aquifers and adjoining oil columns. They isolate either partially or completely an oil reservoir from its aquifer. This results in a rapid pressure drop, a premature high gas-oil ratio and a low primary oil recovery; all of which point to some form of pressure maintenance early in a field's life.

Eventhough tar mats represent considerable hydrocarbon reserves as they are rather common in the Middle East and Africa, it is their impact on oil recovery from adjoining oil columns which is of interest for the time being. Tar must be characterized to evaluate its mobility and ways of establishing contact between an oil column and its aquifer as well as to design an optimum water injection scheme.

The present paper discusses a detailed chemical characterization of tar from a carbonate reservoir in Saudi Arabia. Thermal stability variation was evaluated by thermal gravimetry (TG), and differential thermal analysis (DTA). Elemental analysis of preserved and non preserved samples were carried out with a Carlo Erba 1106 elemental analyser. The sulfur content was also determined by two different ASTM methods. The presence of Nickel, Vanadium and Iron, the major metals usually found in hydrocarbons, was investigated by X-ray fluorescence (XRF) spectroscopy. The tar major hydrocarbon group components were separated and quantified by high performance liquid chromatography (HPLC).

Experimental results showed variation, in tar properties, with depth and area within the same field. The carbon to hydrogen ratio increased systematically with a decrease in API gravity. The sulfur contents obtained with the Carlo Erba elemental analyser were in good agreement with those obtained by the general bomb method (ASTM D-129-64). The content of Hexane insolubles was relatively high at about 38 % by weight. The polar compounds ranged between 5 and 9 % by weight.
Analysis of Scale Inhibitors by Ion Chromatography
Authors: Shuler P. J.
Published: December 2007

This paper compares two ion-chromatography (IC) methods for the analysis of phosphate-based scale inhibitors in oil field brines. Both methods use an anion-exchange column with a nitric acid mobile phase for component separation, followed by mixing with a post-column reagent (PCR). In one method the PCR is an acidic ferric salt solution; the iron-scale inhibitor interaction allows UV detection. The second method uses a PCR containing a strongly fluorescent aluminum-morin complex; elution of a scale inhibitor is detected by a decrease of fluorescence due to the inhibitor complexing some of the aluminum.

These IC methods work only in fresh water, but most salt interferences (especially chloride) may be eliminated by pretreatment through a disposable cartridge containing a resin impregnated with silver. By including a concentrator column, some scale inhibitors can be quantified even at sub ppm levels in saline water.

These IC methods can be used for product quality control and to determine composition changes in scale inhibitors because of process effects such as thermal degradation or selective adsorption/desorption.
Determination of Low Concentrations of Phosphonate in Brines
Authors: Kan A. T. , Varughese K. , Tomson M. B.
Published: December 2007

Phosphonates are widely used as scale and corrosion inhibitors in the industrial environment, but methods of measurement especially at low concentration levels are subject to numerous interferences. The process described herein consists of a digestion step to break-down the phosphonate materials to orthophosphate. The orthophosphate material is extracted into a novel organic phase and measured. The process of extraction eliminates the common interferences to the orthophosphate measurement and allows the accurate determination of phosphonate materials at low levels. The method is suited for measuring phosphonate concentration between 0.1 to 10 mg/1 in brine with a reproducibility of ± 5% at normal concentration. In two hours as many as 20 phosphonate samples can be analyzed by one person using this technique.
Measurements of Polysaccharide Polymer Properties in Porous Media
Authors: Fletcher A. J. P. , Flew S. R. G. , Lamb S. P. , Lund T. , Bjørnestad E. , Stavland A. , Gjøvikli N. B.
Published: December 2007

Accurate determination of polymer properties in porous media is an important input requirement of the reservoir simulation of polymer EOR. Data pertaining to in-situ viscosity and polymer retention are essential parameters which will govern the performance and economics of the application. At reservoir conditions, the acquisition of relevant and precise data is not a straight forward process, but one where extremely careful and reproducible coreflooding experiments are required. We address the question of coreflood procedures best suited to evaluate polysaccharide polymers for field application.

Reservoir condition corefloods should be conducted in non-ferrous metal based rigs to exclude severe face plugging by Fe(lll) gels, which can form when Fe(lll) is present at concentrations greater than 3 ppm. Other sources of face plugging including microgels and incomplete dissolution of polymer must be quantified rigorously. Evidence of face blocking can be assessed rapidly from residual resistance factor (RRF) behaviour, and a measurement of the RRF over the complete flow rate range is essential to characterise polymer behaviour. Quantification of these effects can only be made in experiments with multiple pressure ports, or with two cores in series.

From experiments conducted on a variety of polysaccharide and porous media, using the above procedures, several important findings are reported. All polymers investigated, after fully quantifying face plugging pressure effects, showed a Newtonian plateau at low shear rates. The observed porous media viscosity was lower than that of the bulk, both with and without presence of oil, and can be attributed to slip phenomena. The presence of a residual oil phase results in a lower viscosity for aqueous polymer than that calculated from simple relative permeability arguments. It is shown that polymer viscosity is a function of pore scale tortuosity and wettability, with greatest viscosity loss in highly water wet systems. Polymer retention is a function of polymer type and molecular association. When face plugging effects are quantified, the polymer retention in the remainder of the core is shown in some cases to be very low (less than 10 μg g-1). Polymer retention is dependent on rock type and preparation procedures. In all cases a significant inaccessible pore volume (IPV) of 0.15 – 0.22 was measured.
Field Application of Laboratory Friction Pressure Correlations for Borate Crosslinked Fluids
Authors: Tan H. C. , Shah S.
Published: December 2007

This paper presents (1) test procedures and equipment to model friction pressure behavior of borate crosslinked fluids in hydraulic fracturing operations, (2) effects of various parameters on friction pressure of borate crosslinked fluids, (3) field case histories, and (4) detailed discussion of the implications of findings resulting from this investigation. As a result of this investigation, improved friction pressure predictions are obtained and therefore bottomhole treating pressures have been interpreted more accurately. With a better understanding of formation characteristics from the more accurate BHTP, success rate of stimulation treatments using borate crosslinked fluids has been greatly improved.
Removal of Emulsified Crude Oil From Produced Water by Electrophoresis
Authors: Fang C. S. , Tong N. A. M. , Lin J. H.
Published: December 2007

Emulsified oil droplets in water are surrounded by negative zeta potential, and as a result, they move toward the positive electrode, when an electric potential is applied. This electrophoresis velocity of droplets was measured at various electric potentials, 1.569, 2.61 and 5.23 volts/cm, and various temperatures in the range from 71°F to 116°F. The measured electrophoresis velocity is in the range from 0.4 to 1.6 mm/min, depending upon the electric potential applied.
Identification of Bypassed Gas Reserves Through Integrated Geological and Petrophysical Techniques: A Case Study in Seeligson Field, Jim Wells County, South Texas
Authors: Jirik L. A. , Howard W. E. , Sadler D. L.
Published: December 2007

Bypassed gas zones can be identified and developed by integrating advanced geologic methods and petrophysical techniques into field development strategies. These reservoirs may provide incremental gas reserve additions at relatively low cost to the operator. Seeligson field was studied as part of a Gas Research Institute-sponsored program designed to develop, test, and verity technologies and methodologies for maximizing the recovery of gas from conventional reservoirs in mature fields.

Detailed geologic evaluation of middle Frio reservoirs in Seeligson field reveals a stratigraphic framework composed of multiple, stacked fluvial channel-fill and splay deposits interstratified with floodplain mudstones. Channel-fill deposits are 10 to 40 ft (3 to 12 m) thick and approximately 2,500 ft (750 m) wide. Splay deposits are up to 20 ft (6 m) thick proximal to channels and extend several thousand feet away from the channel. Channel-fill and crevasse-splay sandstones are reservoir fades; levee and floodplain mudstones are thought to be barriers to flow, separating individual reservoirs vertically and laterally.

Recently developed cased-hole log evaluation techniques tested in Seeligson field demonstrate their superiority for locating bypassed gas. Based on geological and spatial considerations, 14 key wells within a 4 mi2 (10 km2) area of the field were selected for cased-hole petrophysical analyses. Pulsed-neutron and gamma-ray logs were recorded in these wells. After preliminary analyses, five wells were selected for full waveform acoustic logging. Porosity was calculated from the acoustic log and compared to pulsed-neutron porosity to determine gas effect. The logs were corrected for shaliness and combined with sigma (capture cross section) data to calculate water saturation. Long-normal resistivity curves from electric logs were digitized and integrated with the newly acquired data to calculate original open-hole water saturation. Plotting and comparing the logs graphically enabled gas-productive sands to be identified.

Five successful recompletions were made as a result of this study. By estimating reserves from current and initial production, using net present value of the gas, and dividing by the cost of the project, a highly favorable return on investment is estimated.
The Gas Research Institute’s Second Staged Field Experiment: A Study of Hydraulic Fracturing
Authors: Robinson B. M. , Holditch S. A. , Peterson R. E.
Published: December 2007

The Gas Research Institute (GRI) is currently sponsoring a field-based research program to better understand the processes that control hydraulic fracture growth. In order to effectively conduct this research and validate the technologies under development, GRI has planned a series of Staged Field Experiment (SFE) wells. These SFE wells, which are drilled specifically for conducting research, are "staged" in the sense that a series of successively higher goals have been set for each well. These goals have been more completely described in previous publications.1 The first Staged Field Experiment was completed in 1987, the results of which have also been published.2,3

The first three SFE wells were planned to be drilled through the Travis Peak formation, while the fourth SFE well is scheduled to be completed in another basin containing significant gas reserves in a tight sand. The purpose of moving SFE No. 4 to another basin will be to apply and test any technologies developed in the GRI program in an entirely differently geologic environment. There are many research technologies that are being developed and tested in the SFE program, but the primary objective was to develop a fracture monitoring and fracture modeling system that could compute the shape and extent of a hydraulic fracture in real time. In order to obtain accurate and reliable input data for the fracture models, it was necessary to perform studies on geology, coring, logging, and well testing of tight gas sands. In an effort to substantiate and verify the models, additional research is being sponsored in the development of instrumentation and analysis techniques for measuring the dimensions of the fracture.

The second Staged Field Experiment, officially known as SFE No. 2, was successfully completed in 1989. An extensive amount of data was collected on this well from two different intervals of the Travis Peak that were tested and fracture stimulated. The purpose of this paper is to summarize all of the data that were collected and the analyses performed on these data. As a result of the work performed on SFE No. 2, a great deal was learned with regard to the completion and stimulation of the Travis Peak formation. A new strategy with regard to completion and stimulation of wells was developed that utilizes the integration of openhole log and in-situ stress data. These results are presented for the Travis Peak. Hopefully, this same approach can be applied on most tight gas sands.
Field Applications of Wireline Formation Testers in Low-Permeability Gas Reservoirs
Authors: Desbrandes R. , Yildiz T.
Published: December 2007

Wireline formation testing (WLFT) is a downhole testing technique used to determine the formation pressure, the formation pressure gradient, and the formation permeability and to collect formation fluids. Current WLFT tools are designed for high to medium permeability reservoirs. In this study, the results from WLFT runs in eight wells drilled in cooperation with the Gas Research Institute are presented. The tests were conducted by three major service companies. The merits of the WLFT tools, the information provided, and the possible misinterpretations of the data are reported.

A brief description of each formation tested is made in each well: rock type, shaliness, porosity, permeability, saturation, and formation pressure. The test results are characterized by the flowrate, the chamber size, the duration of drawdown, and the duration of the pressure buildup. Typical curves are presented. A statistical study of the successful tests is attempted.

The results obtained with a slow flow wireline tester (SFWT) are also presented. Based on the analysis of the SFWT runs and using a new modeling technique, a new interpretation method is proposed. The results indicate that the current WLFT tools will have to be modified to allow a better analysis of the drawdown period.

This study shows that meaningful data can be obtained with the WLFT tool in many instances, especially when a slow flow rate is used. The drawdown portion as well as the build-up portion of the pretest can be interpreted, and the drawdown data can confirm or, to some extent, replace the build-up data. The evaluation of low permeability gas formations will be greatly enhanced by using the new slow flow testers and the new interpretation technique.
Interpreting Short-Term Buildup Tests From Low-Productivity Gas Wells Using Deconvolution
Authors: Johnston J. L. , Lee W. J.
Published: December 2007

This paper illustrates the application of deconvolution to analysis of wellbore storage distorted pressure buildup test data from low productivity gas wells. These wells generally require long times to reach tie correct semilog straight line, rendering conventional Horner analysis impractical. The deconvolution process removes the effects of wellbore storage and allows for the use of semilog analysis. Also, times required for buildup tests can be reduced by more than an order of magnitude with no loss in accuracy in results. In fact, analysis is sometimes even more definitive with the short-term, corrected test data than with much longer-term but uncorrected data because some important characteristics of a formation (such as the effects of layering or dual porosity) appear only in the first few hours of shut-in and are usually masked by wellbore storage distortion.

The problem with deconvolution is that it requires accurate sandface rates after shut-in. These rates are difficult and expensive to measure, so we present a method to calculate the sandface rates from the observed pressure buildup data. This paper presents verification of the rate calculation and the use of the calculated rates in deconvolution with simulated data. We also present several field cases from low permeability gas wells. The success of the deconvolution analysis implies that shorter tests may be run on low productivity gas wells, significantly reducing the cost of the tests and increasing opportunities to identify important reservoir heterogeneities.
The Effect of Microsilica on the Thermal Stability of Lightweight Cement Systems
Authors: Dillenbeck Robert L. , Mueller Dan T. , Orr Billy R.
Published: December 2007

In various formulations, microsilica cement slurries are finding increasing utility in oilfield cementing applications. In the course of these applications, many microsilica slurries are being used in environments which subject the set cement to bottom hole static temperatures in excess of 230°F.

While 35% fine silica by weight of cement (BWOC) has been extensively researched and accepted as a high temperature cement stabilizer, very little if any research has been published on the effectiveness of microsilica in this application. The results of this study reveal that microsilica displays promise as a viable alternative stabilizing material, with the added benefit of medium to low slurry density.
The Use of Selective Injection Equipment in the Rangely Weber Sand Unit
Authors: Franks A. P.
Published: December 2007

Selective injection equipment (SIE) has been used in the Rangely Weber Sand Unit to improve the vertical conformance of both a mature waterflood and a full-scale CO2 flood. The Ershaghi technique of waterflood reserves estimation shows that SIE has improved ultimate waterflood recovery by approximately 6.6% of the original oil in place. Scoping economics, applied to historical production data, show that this additional oil recovery is profitable.

The application of SIE to the Rangely CO2 Project is reviewed, including information on corrosion, SIE run life, and the technique of "blanking" high-permeability thief zones to reduce inefficient cycling of CO2. A discussion is presented on SIE optimization through the use of injection profile data, permeability information, production and injection data, and reservoir simulation. The paper concludes by addressing the feasibility of applying SIE to other oil fields with similar reservoir characteristics.
Alternative Use of ESP's for Water Injection
Authors: Foote T. J. B. , Stalder J-P.
Published: December 2007

This paper describes the use of electrical submersible pumps (ESPs) for the enhancement of water injection on the BP operated Ula platform, situated in the Norwegian sector of the North Sea. The pumping scheme was designed to use off-the-shelf pumping equipment, in a manner not normally used in the offshore North Sea environment, to meet the requirements of rapid installation, minimum use of valuable deck space, high suction pressures and a high degree of safety in operation. Taking suction from the existing water injection manifold at 220 barg, two pumps in parallel were required to boost the injection pressure in two wells to 330 barg, and achieve a total injection rate of 25,000 bpd (3,975 m3/d).

To cope with the high suction pressure each ESP was housed in a suction can, capable of taking the full suction pressure, constructed mainly from off-the-shelf standard well casing. The pump/can units, each around 35 metres long, were installed in spare well conductors, resulting in minimum use of deck space.

The pump system was in operation for 9 months until the permanent uprated water injection system was commissioned.
A Practical Approach to Prevent Formation Damage by High-Density Brines During the Completion Process
Authors: Baijal S. K. , Houchin L. R. , Bridges K. L.
Published: December 2007

The potential for formation damage caused by the use of high density brines has only recently begun to be studied. Unfavorable fluid/rock interaction has been shown to produce mobile fines and swelling clays with the added potential for the precipitation of brine insoluble salts. Some operators have started lowering the pH of CaCl2 and/or CaBr2 brines by requiring a minimum of 8% ZnBr2. The hope was to prevent the precipitation of acid soluble salts. This approach has significant practical and economic limitations. This study evaluates alternatives to use of ZnBr2 as a primary component of standard CaCl2 and/or CaBr2 brines. Laboratory core flow tests were conducted to evaluate surfactant systems potential for preventing this formation damage.
Electronic Gas Measurement Deployment/Development Considerations
Authors: Allen J. M.
Published: December 2007

During the last few years, Amoco Production Company has identified concerns that needed consideration before deciding on the pursuit of Electronic Gas Measurement / Electronic Flow Calculation (EGM/EFC). Those considerations include 1) defining the existing system of measurement and volume calculation, and 2) defining the benefits EGM/EFC could provide and the functions required of the devices to provide those benefits. Then identified were the limitations of the various options that meet the functional requirements, and various other considerations.

Anyone who is considering EGM/EFC for their operations should weigh all the points made in the paper before a decision is made. Occasionally, not all the points or their interactions are identified in the decision process.

By having all the options and their interactions explained, prudent decisions on the deployment of EGM/EFC can be made. If careful consideration of the functions required to gain the expected benefits is made initially, the result will be reduced overall expense. These savings are from not installing additional equipment that attempts to provide the necessary beneficial functions. After full consideration, deployment of EGM/EFC devices may prove to be an effective alternative to the traditional chart recorder technology, but may not be appropriate for all applications.
Yield Points in Oilfield Cements
Authors: Clark P. E. , Sundaram L. , Balakrishnan M.
Published: December 2007

The determination of yield points in cement slurries is important in the complete description of slurry flow properties. Yield points affect both the start-up pressure after a temporary shutdown and void filling properties of cements. Values for the yield point are normally obtained by extrapolation of rotational or tube flow rheometer data. This technique is subject to both experimental and analytical errors.

Recently, several papers have described a more direct method of measuring yield points in slurries. A rotational viscometer equipped with a vane rather than a bob can be used to measure yield points accurately. The yield surface with the vane test fixture is in the fluid rather than at a fluid-solid interface as it is with a solid bob or a tube flow apparatus. Experiments with a vane fixture using a shear rate controlled rheometer can be subject to errors caused by windup of the torque spring. In this study a controlled stress rheometer was used to circumvent these problems.

Yield points for various oilfield cement slurries are presented. Data reflect the differences in additives, aging time and water content. The vane technique can be used to produce accurate and reproducible measurements of yield points in cements. Using a controlled stress instrument has several advantages in making these measurements.
Evaluating and Establishing Safety Ratings for Submersible Cables
Authors: Durham M. O. , Ashenayi K. , Guzy R. , Lea J.
Published: December 2007

This document will define procedures to evaluate cables used with electrical submersible pumps (ESP). A standard rating system based on the performance results will be advanced. This system of scoring will permit the selection of a safe and suitable cable for the environmental requirements of a well. It is not the intent of this publication to specify what cable should be used or in any way set up a series of requirements that must be met before a cable may be run in a well.

This procedure will describe the evaluation techniques in detail, establish a standard reporting form for results, and set forth a rating system for each type of cable. The procedures outlined here are for samples of generic cable types. The prescribed evaluations are best done in a controlled environment by an independent laboratory.

Unlike test procedures whose objective is to qualify whether a cable works or not, the objective of this research is to quantify the performance degradation in various conditions.
Optimum Cable Selection for Electrical Submersible Pumps
Authors: French S. W.
Published: December 2007

This paper discusses common methods of power cable design for electrical submersible pumps and presents a new method which can result in a more optimal design. A procedure is developed for estimating the maximum expected operating temperature of the conductor for each cable size. An accurate selection of power cable insulation type can be made for each cable size based upon the maximum operating conductor temperature. Total cable investment cost can then be determined for each cable size. Power loss calculations are also provided to predict the power cost of the cable. The final cable selection can be determined by economic analysis. Other factors that should be considered when selecting the cable for a specific ESP installation are also discussed.
Sorption and Fate of Phosphonate Scale Inhibitors in the Sandstone Reservoir: Studied by Laboratory Apparatus With Core Material
Authors: Kan A. , Yan L. , Bedient P. B. , Oddo J. E. , Tomson M. B.
Published: December 2007

Phosphonates are commonly used in the petroleum industry to control scale and corrosion. In order to understand the fate of phosphonates in the reservoir after an inhibitor squeeze, both the kinetics and the equilibrium aspects of phosphonate sorption have been studied in the laboratory using batch apparatus and sandstone core flow-through apparatus. Diemylenetriaminepenta(methylene phosphonic acid) (DTPMP) was used in the experiments. The adsorption process includes the following four stages: (1) molecular diffusion; (2) dissolution of mineral from sandstone surfaces; (3) adsorption; and (4) solid phase maturation. The adsorption is kinetically important and the amount adsorbed is affected by both flow velocity and calcium concentration. A new radial-flow transport equation to simulate the transport of phosphonate in an inhibitor squeeze is also reported.
Design and Field Testing of Matrix Acid Diversion Treatments in Widely Varying Permeability Zones
Authors: Dietrich M. J. , Hunter W. L.
Published: December 2007

The effectiveness of matrix acid stimulation treatments is limited in widely varying permeability zones due to poor diversion. A unique combination of nitrogen foam, oil-soluble resins and HEC diversion agents was developed to ensure complete acid contact throughout the multiple layer zones in a gravel packed offshore Gulf Coast Louisiana well. Through the use of radioactive tracers and on-line pressure monitoring of the tubing and annulus, onsite adjustment of diverter concentration at various points during the treatment was achieved. The diversion of acid throughout these widely varying permeability zones was proven effective based on two logging runs and observed surface pressure responses. The case history with supporting data is included in the paper.
Maximizing Injection Rates in Wells Recently Converted to Injection Using Hearn and Hall Plots
Authors: Jarrell P. M. , Stein M. H.
Published: December 2007

A new technique is presented which aids in maximizing water injection rates in wells recently converted to injection, thereby accelerating offset oil production response. This method is applicable to waterflood operations where injection wells are surface pressure controlled and where bottom-hole injection just below formation parting pressure (FPP) is desired.

Two plotting methods are shown to be instrumental in monitoring the acceleration of fill-up and average reservoir pressure growth in an actual field case. One is the Hall method1: plotting a function of bottom-hole injection pressure versus cumulative water injection, and the other was Introduced by Hearn2: plotting the inverse injec-tivity index versus cumulative water injection.

After initiating injection into several converted wells at pressure limits well below the average offset parting pressures, periodic surface pressure increases were made at each well over a period of several months. Monitoring the Hall and Hearn plots as the pressure and rates increased rendered qualitative interpretations of whether the rates were being maintained below FPP. Accelerated reservoir pressure growth was achieved which resulted in earlier than expected offset oil response.

Application of these plots also reduce, and sometimes eliminate, the need to perform periodic step-rate tests designed to determine FPP during the injection start-up period, thereby significantly reducing operating costs.
Transient Analysis of Point Arguello Gas Pipeline Behavior
Authors: Sarica C. , Shoham O. , Brill J. P. , Taitel Y.
Published: December 2007

The sour gas produced from the offshore Point Arguello oil field will be transported through a pipeline consisting of offshore and onshore sections terminating at an onshore processing plant. Accurate prediction of the complex flow behavior of the fluid in both pipeline sections is essential for proper operation of the pipeline. The objective of this paper is to analyze and provide engineering solutions for the operational problems occurring during the different production phases of the field.

It was found that the Point Arguello pipeline would exhibit different flow behaviors, depending upon the input flow rates. A simplified, flow pattern dependent, transient two-phase flow simulator was used to predict this complex flow behavior. For low input flow rates the offshore pipeline section would operate under slug flow conditions, with liquid accumulating in the line, and frequent pigging being required. For high input flow rates, the offshore pipeline section would operate under stratified flow, resulting in less liquid accumulation and liquid being transported into the onshore section. These different operational modes play an important role in leak detection analysis.

The rigorous analysis of the complex flow behavior presented in this paper provides solutions for proper operation of offshore wet gas pipelines. This includes solutions for liquid accumulation, pigging frequency, and pressure fluctuations for leak detection.
Pipelining of Heavy Crude Oil as Oil-in-Water Emulsions
Authors: Zhang Jingjun , Chen Dabin , Yan Dafan , Yang Xiaoheng , Shen Chen
Published: December 2007

This paper presents an exDerimental study on pioelining of Shanjiasi heavy crude oil as oil-in-water emulsions. Viscosity reductions of more than three orders of magnitude were achieved in laboratory by emulsification. Field trials were then made in three 4-in. gathering lines 101, 160 and 241 meters long respectively. A chemical solution was injected into the gathering line at the wellhead. Drag reductions of 40-80% were achieved provided that the formed emulsions had an injected water fraction of 0.2-0.4 and the chemical concentration was at 0.35-0.5% (based on injected water). It was also found that drag reduction was more significant at a low temperature and for a highly viscous heavy oil. A big difference existed between rheologi" cal data obtained from the field trials and those from laboratory experiments, and possible reasons were discussed.