bluuebunny/crossref_metadata_2025 huggingface dataset:
New Analysis Technology for Determining Fracture Parameters from Calibration Treatments: Case Histories, Rocky Mountain Area
Authors: Warembourg P. A.
Published: December 2007

In May 1987, an innovative technique was presented to the industry by J. L. Castillo that introduced a new plot for fracture pressure decline analysis ("Modified Fracture Pressure Decline Analysis Including Pressure-Dependent Leakoff" (SPE 16417)).1 The plot is used to determine the pressure parameters (PC, P*) required in the Nolte leakoff calculations. The plot also set the stage for an analysis technique that enhances the square root of time plot to determine closure, and the Nolte type curves to determine P*.

Case histories demonstrate how the analysis technique is applied. The technique uses a combined analysis and simulator program to determine P*, total leakoff coefficient, closure pressure and closure time. These parameters are determined from a single calibration treatment. Advantages of the technique include speed and simple operation. An estimation of fracture height created during the calibration treatment is also made. Fracture height is a critical parameter that is not always available unless reliable surveys are performed after a calibration treatment. This is not to imply that surveys can now be eliminated. Surveys should always be run whenever possible to confirm height. There will invariably be discrepancies in determining fracture height, because surveys show the best case (inclined vs true vertical fractures), and calculated heights using three-dimensional (3D) simulators require more data than are usually available.

The case histories show the comparison between the heights determined by the analysis and the heights determined by surveys. The other calculated parameters are given for several formations and locations. The importance of the input and output parameters used in the case histories is discussed. Fracture height and total system leakoff are two critical variables needed for efficient fracture design. The method to obtain these variables and their value is presented.
Field Cement Sampling and Testing: A Case Study in the Madden Deep Unit, Wyoming
Authors: Reeves N. K.
Published: December 2007

Drilling and cementing in the Madden Deep Unit of west central Wyoming is characterized by formation pressure variances, gas influx and lost circulation problems. These problems must be considered when designing cement slurries for each casing and liner job. Consideration must also be given to the fact that large volumes of cement are required for these jobs.

To maximize the success of each cement job, extensive laboratory pre-testing and field blend testing are conducted prior to moving cement to location. This procedure consists of designing and testing a cement slurry to meet such parameters as thickening time, fluid loss control, compressive strength development and hydrostatic pressures. This pre-testing is followed by testing each load of field cement blend to detect any deviations from the pilot cement.

This paper will discuss such aspects of the field blend testing as bulk plant sampling, acceptable thickening time windows, test repeatability, and the use of dry additive identification. A major point will show how the use of dry additive identification is a very valuable and time saving tool in the testing of field blends.
Water Resistivity from Spontaneous Potential Logs in the Minnelusa Formation, Powder River Basin, Wyoming
Authors: Policky B. R. , Iverson W. P.
Published: December 2007

Water resistivity (Rw) values computed from the spontaneous potential (SP) log frequently yield low values for the Minnelusa formation of the Powder River Basin, Wyoming when compared with Rw values determined directly from water samples. These anomalies arise when conventional SP analysis techniques for obtaining Rw are fallowed. Therefore, a new technique for determining the SSP deflection and a new equation which salves for Rw have been developed.1

To construct and validate the new technique and equation, a complete appraisal of the current methods of obtaining estimates for water resistivity has been provided. A substantial number of wells, which produced 100% water upon testing and span a large cross-sectional area of the basin, were analyzed. In addition, oil producing wells have been included to verify Rw estimates for intervals bearing hydrocarbons.

Using this new procedure has resulted in significant improvements in the accurate evaluation of the hydrocarbon potential of a prospective interval within this formation.
Multiple Hydraulic Fracture Propagation in Oil Sands
Authors: Chhina H. S. , Best D. A. , MacKenzie W. T.
Published: December 2007

A multiple hydraulic fracture field test was conducted in the McMurray formation of the Athabasca oil sands in Alberta, at a depth of 235 mKB. Due to the low fluid injectivity into the formation, hydraulic fracturing preceding hot water and/or steam injection was considered a viable means of establishing interwell communication. In situ stress tests conducted at the wells indicated the minimum principal stress to be in the vertical direction. This meant horizontal fracturing was feasible at 235 mKB. Subsequently two fracture treatments were conducted, a mini-fracture test followed by the main propped fracture. The fracture monitoring methods used were as follows:

Tiltmeters Temperature observation well Radioactive proppant Fracture extension pressures Post fracture log evaluation wells

Tiltmeter and observation well data indicated horizontal fracturing during the mini-fracture test. The subsequent main fracture treatment showed similar results during the initial injection stage, however evidence of vertical fracturing was prevalent during the proppant injection stage. Numerical modelling conducted at a later date, using a finite element stress-strain model, indicated that in a near isotropic stress environment there existed a critical maximum formation strain, beyond which the minimum principal stress direction can change. As a result of the above work, the fracture design parameters for oil sands, such as injection rates and fracture fluid viscosities can be adjusted to minimize vertical fracturing at shallow depths, where initially horizontal fractures are favoured.
Diesel-Based Gel Concentrate Improves Rocky Mountain Region Fracture Treatments
Authors: Yeager R. R. , Bailey D. E.
Published: December 2007

More than 500 oil and gas wells in the Denver-Julesburg (D-J) Basin have been successfully stimulated using a water-base fracturing fluid, gelled with a diesel-base gel concentrate. Since the use of this system began in 1985, six different D-J Basin formations, with bottom hole temperatures ranging from 120°F to 260°F, have been treated. Ammonium chloride and potassium chloride have both been used with the continuously mixed gel to help protect clays.

This paper presents a brief description of the chemistry of the system, however, the main emphasis of the paper is toward operational considerations and economics of using diesel-based gel concentrate. The considerations include continuous (on-the-fly) mixing of the gel and an evaluation of ammonium chloride versus potassium chloride for clay protection.
A Summary of the Big Muddy Field Low-Tension Flood Demonstration Project
Authors: Borah M. T. , Gregory M. D.
Published: December 2007

A 90-acre demonstration of the low-tension flood process was recently completed in the Second Wall Creek reservoir of Wyoming's Big Muddy Field. This paper addresses the overall performance of the project, including a comparison to the laboratory design. It also discusses some of the practical aspects of a low-tension flood.
Early Kick Detection Holds Kill Pressure Lower
Authors: Griffin Phil
Published: December 2007

This paper was prepared for the SPE Symposium on Mechanical Engineering Aspects of Drilling and Production to be held in Fort Worth, Tex., March 5–7, 1967. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor of the appropriate journal, provided agreement to give proper credit is made.

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.

Within the last year the oil industry has undergone a tremendous self-training program with respect to the application of engineering theories to the control of threatened blowouts. This education program has considered both highly technical and comp] i ca ted systems for use by drilling engineers and has also considered highly simplified systems for use by rig floor personnel and other non-engineer supervisory personnel. This paper restresses the need for the continuance of this educational program and points out primarily for rig and non-engineering personnel the necessity of detecting a kick as early in its life as possible. Surface indications that a kick is in progress are discussed. Kick detection instrumentation is also discussed. Examples are shown whereby early kick detection can hold pressures required to bring the well back under control within both surface and downhole pressure limits.

Within the last year the oil industry has undertaken a self-training program with respect to the application of engineering theories to help control threatened blowouts, This education program has considered both highly technical and complicated systems for use by drilling engineers and has also considered highly simplified systems for use by rig floor personnel and other non-engineer supervisory personnel.

The theories of Gulf Oil Company's Goins and O'Brien have been studied, modified, expanded, condensed, subjected to computers, and field tested and generally have become widely accepted by the industry. The whole key to the Goins-O'Brien approach is the establishment and maintenance of a constant and sufficient pressure in the annulus opposite a producing formation.

Goins and O'Brien have shown that the drill pipe-well bore combine to behave similar to a simple "U" tube (figure 1) and being such react to a downhole situation as a "U" tube would be expected to react to a similar situation. Further investigation of "U" tube theory shows that the pressure at the "top of the tubes" can be used to determine the pressure at the bottom of the "U".
Development and Application of New Type Curves for Pressure Transient Analysis
Authors: Yeh N-S. , Agarwal R. G.
Published: December 2007

Use of type curves based on the dimensionless pressure and its logarithmic derivative has become a standard method for analyzing well tests data. Recently, a new procedure for constructing type curves using a dimensionless pressure group which involves the ratio of the dimensionless pressure and its derivative was developed and reported in the literature. This paper extends the preceding concept not only to the pressure variable but also to the time variable. That is a new dimensionless time group is introduced for type curve construction. The major advantage of this is that the matching procedure requires the movement of the field data only in the horizontal direction. This improvement not only facilitates the type curves match but also increases the reliability of the analysis results.

New type curves are presented for wells in radial systems with wellbore storage and skin, and vertically fractured wells with uniform-flux, infinite-conductivity and finite-conductivity fractures. Field examples are included to illustrate the utility of the new type curves and the analysis procedure. The possible application of this method to heterogeneous systems such as naturally reservoirs are also discussed.
Reservoir Descriptions Via Pulse Testing: A Technology Evaluation
Authors: Chopra A. K.
Published: December 2007

Implementation of pulse testing technology as a tool to obtain reservoir descriptions has been limited to only certain types of reservoir heterogeneities. An integrated approach to evaluate pulse testing as a means of obtaining reservoir descriptions for multilayer heterogeneous reservoirs is presented in this paper. A method is developed to simulate pulse tests using a gridded model. Pulse test responses in multilayer heterogeneous reservoirs are investigated for unequal layer pressures, vertical layer heterogeneities, and wellbore storage effects both at the active and observation wells.

The integrated approach is applied to a pulse test pilot completed in a San Andres reservoir. The usefulness of pulse testing is found to be highly reservoir specific. Pulse test data alone are not sufficient to derive reservoir descriptions for multilayer heterogeneous reservoirs and must be used in conjunction with geological, petrophysical, and single well pressure transient data. Pulse testing may not provide an adequate definition of vertical layer heterogeneities for tertiary miscible gas performance predictions and can be used only to refine the definition of high speed layers which control gas cycling in a tertiary miscible gas process. The pulse test derived reservoir description may be adequate for waterflooding predictions under certain situations. For primary depletion predictions, single well pressure transient data are sufficient when coupled with geological and petrophysical data. The integrated approach to evaluate pulse testing is recommended before actually conducting pulse tests in the field.
Comparative Rheology of Water-Based Drilling Fluids With Various Clays
Authors: Güven N. , Panfil D. J. , Carney L. L.
Published: December 2007

Water-based drilling fluids comprising different clays (bentonite, saponite, and sepiolite) have been autoclaved in the temperature range of 300–600°F (149–316°C) under appropriate confining pressures in order to simulate the conditions encountered while drilling deep oil and gas wells. The clay mineral saponite represents the magnesium analog of montmorillonite which is the aluminous clay mineral in bentonite. Both montmorillonite and saponite are characterized by a swelling silicate lattice and an excess layer charge. Morphologically, saponite and montmorillonite are similar and they consist of thin platelets and films mostly in the micron-size range. Sepiolites are similar in chemistry to saponites but they possess a fibrous morphology and a neutral lattice. These basic characteristics of the clays are found to lend different rheological and wall-building properties to the drilling fluids. Saponite fluids display much higher viscosities and significantly lower fluid losses at high temperatures. Saponite fluid was also more stable than bentonite fluid at high temperatures and in the presence of common Na, K, and Ca salts and hydroxides due to the nature of reactions between these compounds and bentonite. Mixing fibrous sepiolite with saponite enhances the viscosity of these fluids in the presence of common salts. At high temperatures sepiolite readily converts to a smectite and improves the fluid rheology and fluid losses.
Coiled Tubing in Horizontal Wells
Authors: Cooper R. E.
Published: December 2007

Coiled tubing is an effective tool in logging and workover applications of horizontal wells. Several operators have taken advantage of using coiled tubing to log or perforate wells which could not have been performed with conventional wireline methods. Specialized surface and subsurface equipment has been developed to facilitate the use of wireline tools with coiled tubing.

Production logging data, particularly multiphase flow testing, in horizontal wells have proved difficult to interpret. The use of coiled tubing packers and flow diverters to help isolate flow rates has improved production profile data.

Coiled tubing has been used to selectively place stimulation fluids over long sections of horizontal hole, i.e., 1,200ft (366m) and greater. It has also been used in zone isolation, cement squeezing, and setting of bridge plugs. Several cases are presented where the use of coiled tubing eliminated or reduced conventional rig expense.
Performance of Vertical and Horizontal Wells in Reservoirs Containing Discontinuous Shales: Numerical Studies of Two North Sea Fields
Authors: Borner D. L. , Haldorsen H. H. , Harrison P. F. , Hopwood A. P. , MacDonald C. J.
Published: December 2007

Many reservoirs contain a thin oil column with underlying water or with a gas cap present. To decide on the viability of such fields, detailed single-well simulation studies are often made to forecast oil, gas and water rates through time. This paper investigates the effects of discontinuous shales on the performance of vertical and horizontal wells in these reservoirs. Stochastic techniques are presented for representing shales on a simulation grid.

Conclusions are that it is necessary to include shales explicitly if the variability of behaviour in vertical wells is to be captured; that shales cutting the wellbore have the most significant effect on performance; and that small shales can be represented via an effective vertical permeability for horizontal well simulation.
Numerical Simulation of Gravity-Stable Hydrocarbon Solvent Flood, Wizard Lake D-3A Pool, Alberta, Canada
Authors: Hsu H. H.
Published: December 2007

This paper presents a history match and prediction for the Wizard Lake D-3A pool reservoir in Alberta, Canada. The reservoir is a dolomitized bioherm reef with an initial oil pay zone of 648 feet (197.5 m) and it is underlain by the Cooking Lake aquifer. A fieldwide 3-D (11×14×53), 4-component (gas, solvent, oil, water) simulation model is used to history match the reservoir pressure, the oil, gas, and water productions, the gas/solvent, solvent/oil, and oil/water contact locations. This paper will address several features of the model which were developed specifically for this study. These include treatment of openhole completion and handling of solvent and water coning with the coarse grid model. It will also discuss different methods of calculating the fluid contact locations from simulation results.

The history match covers a time span of 3 6 years (1951–1986). The reservoir was initially under primary production for 19 years during which reservoir pressure dropped below the bubblepoint pressure and a secondary gas cap formed. Hydrocarbon solvent flooding started in late 1969 and continues to the present time. During the solvent flood, both residue gas and water were injected to raise the reservoir pressure back to its original value. At the completion of the history match, the model was used to make prediction runs to assist in planning the pool’s production and injection strategy.
Phase Equilibria for Enhanced Oil Recovery in an n-Butane Enriched Carbon Dioxide + Black Oil System
Authors: Chaback J. J.
Published: December 2007

Discussed herein are three aspects of fluid phase equilibrium as they relate to enhanced oil recovery processes and to the simulation of such processes. First, experimental phase equilibria measurements show that the addition of n-butane can lower saturation pressures relative to those of base oil + CO2 mixtures. Enrichment of the injection gas with only 10 mol·% n-butane reduces the saturation pressure at the L-V critical point by 1400 psia [9.65 MPa] and by nearly 2250 psia [17.51 MPa] for a 20 mol·% addition. Likewise, addition of 6 mol·% n-butane reduces the slim tube minimum miscibility pressure by approximately 550 psia [3·79 MPa]. Thus, a n-butane enriched CO2 injection gas can achieve multiple contact miscible displacements in lower pressure reservoirs. It would not be possible to miscibly flood those low pressure reservoirs with pure CO2 injection.

Second, phase distribution curves from constant composition volumetric expansion experiments illustrate the solvent capacity of the injection gas for the base oil.

Third, a set of equation of state parameters describing the fluid PVT and phase behavior is presented and used to represent the suite of measured properties. To mimic miscibl·e-like behavior during multiple contacting, severe compromises are required in the representation of base oil and first contact base oil + injection gas mixture properties.
Selection and Operation of Production Facilities for Handling High Pourpoint Crude Oils
Authors: Buyzen J. P. , Potter G.
Published: December 2007

The increasing capital and operating cost of production facilities, together with the decrease in the value of the produced barrel have given impetus to achieving acceptable product unit cost whilst providing operable and maintainable plant. The review of operations philosophy, field development plan and mode of operation is a way to achieve this goal.

Contractual and environmental obligations of oil companies have resulted in a change in practice of controlling the production of individual fields towards an overall approach of operating integrated systems, thus ensuring system flexibility in a buyers market situation.

The paper discusses the effect of the Operations Philosophy on design and selection of surface and subsurface facilities in fields producing a high pourpoint crude oil. A general discussion is followed by a more specific look at a recent project and development in Gabon (West Africa).

The field described (Rabi) was discovered by Shell Gabon in 1985 some 130 km north from their existing fields and export terminal. Crude oil will be degassed in four gathering stations, each 40,000 b/d capacity, and dehydrated and metered in a central plant, capacity 140,000 b/d, prior to pumping to two export terminals operated by Elf and Shell respectively.

Specific attention is paid to preventing and combatting wax deposition in surface and subsurface facilities and the influence on pumpability and restartability of crude in the minimum pourpoint condition and application of wax interaction modifiers.

The paper highlights the importance of operations input during initial field development and its effect on facilities selection, mode of operation and operating cost.
Why Cement Fluid Loss Additives Are Necessary
Authors: Baret J. F.
Published: December 2007

With respect to the fluid loss behaviour of a cement slurry basically two stages need be considered: (i) a dynamic one corresponding to the placement and then (ii) a static one, the waiting on cement. During the first period the slurry flow is eroding the filter cake as it is growing, thus rapidly a steady state is reached where the filtration occurs through a cake of constant thickness; at the same time, since the slurry is losing water but no solid particle, its density is increasing in line with the fluid loss rate. During the second period, referred to as "static", the cake grows due to the absence of flow. It may possibly grow up to a point where it locally but completely fills the annulus: bridging takes place and the hydrostatic pressure is no longer transmitted to the deeper zones.

Dynamic:A maximum acceptable value of the total volume of fluid lost during the cement placement can be easily calculated from an upper density limit. Since basic slurry properties, like thickening time and rheology, are greatly dependent on density (at least in the low water content domain), they may be used to define this limit. To convert the total amount of fluid loss into an API fluid loss value, three parameters are needed: the permeable formation area, the mudcake thickness and its permeability.

Static: A maximum acceptable value of the thickness of the cake built-up during the waiting on cement period is deduced from the annular gap. The time taken by the filter cake to completely fill up the annulus, i.e., the bridging time, depends on the cement and mud cake properties (mudcake thickness and permeability and cement cake permeability). Therefore, by comparing thickening time and bridging time, a maximum value for the cement cake permeability can be deduced which is then expressed as an API fluid loss value.

From typical mudcake resistances it can be estimated that, both in dynamic and in static conditions, the fluid loss could, in some conditions, have to be reduced to an API value one order of magnitude lower than what is generally considered as a fair control of fluid loss. Some examples are given. However, still very little is known about the effect of spacers, washes, mechanical aids and cement itself on the mudcake state and more data have to be gathered on mudcake thickness and permeability under various conditions, before definite fluid loss limits can be asserted.
Numerical Simulation for Planning and Evaluation of Polymer Flood Process: A Field Performance Analysis
Authors: Maitin B. , Daboul B. , Sohn W. O.
Published: December 2007

A polymer flood process with partially hydrolized Polyacrylamide solution in fresh water has successfully been applied "by Deutsche Texaco AG in the oilfields of Hankensbuettel and Oerrel. The flood process is capable of recovering additional 10–15 % 00IP in high salinity reservoirs with temperatures of 60 °C and oil viscosity up to 20 mPa.s.

This paper presents the case history of Oerrel West Block Polymer Flood and demonstrates the importance of comprehensive reservoir description by numerical simulation.
A Comprehensive Quality Assurance Program for Offshore Production Facilities
Authors: Lee S. L. , Aw C. L.
Published: December 2007

The paper describes the Quality Assurance (QA) Program developed by ESSO Production Malaysia Inc. (EPHI) to ensure that its offshore production facilities remain in a safe operating condition through a monitoring and preventive approach. The program has to accomodate the different phases of hydrocarbon recovery at the different fields; the concerns associated with a significant amount of CO2, increasing watercut, and emergence of sulphate reducing bacteria (SRB); the weathering of facilities in a hot and humid environment; and the aging of the existing producing facilities.

The monitoring and control programs used by EPMI to address the above concerns are described. The monitoring programs include structural inspection with remote operated vehicles (ROVs) and divers using non-destructive testing (NDT), and facility inspection employing techniques such as water analyses for pH, iron count and SRB, ultrasonic thickness measurements, corrosion coupons and probes, caliper surveys and vessel/pipeline inspections. The corrosion control programs include the use of corrosion inhibitors, pigging, cathodic protection and coatings.
Changing Development Patterns in the Gippsland Basin, Offshore Southeast Australia
Authors: Hordern M. J.
Published: December 2007

Three phases of Gippsland offshore development can be recognised. In the initial phase, the largest oil fields, because of their excellent reservoir quality, were developed simply with low angle wells located crestally draining large reserves. Fields in the second phase have required more costly and complex developments including high angle or deep wells because of field geology and hydrocarbon distribution. Reserves in these fields are substantially lower.

A third phase has commenced in which some of the many small fields remaining will be developed via mini platforms, subsea satellites and single-leg structures, to partially offset the rapidly declining production of the earlier fields.
Synergetic Log and Core Data Treatment Through Cluster Analysis: A Methodology to Improve Reservoir Description
Authors: Descalzi C. , Rognoni A. , Cigni M.
Published: December 2007

Nowadays the most efficient method for quantitative log interpretation calls for an integration of all the information available (logs, cores, well tests) which is then synthesized and homogenized. This allows obtaining more and more reliable and detailed values concerning the lithological, petrophysical parameters and, thence, the internal structure of the reservoir.

As a consequence, it is fundamental to unify all the log and core information into a global data base taking into account both the qualitative (lithology) and quantitative (petrophysical parameters) data.

To reach this target, it is essential to start from a detailed lithological analysis and to have the availability of a number of logs sufficient to discriminate and, thence, quantify all the mineralogical components defined by means of core analysis.

For this purpose a model based on a linear programming algorithm for the quantitative interpretation has been conceived so as to evaluate all the characteristics highlighted by the quantitative analysis.

Applications of this methodology to complex lithologies are shown in several examples. Emphasis is given to a detailed analysis of the advantages of this methodology, that is: –unification of all the log and core information into a single interpretative process.–Adaptability of the program to all log sets and local conditions.
Horizontal Wells Cut Offshore Production Costs
Authors: Giannesini J. F. , Bosio J.
Published: December 2007

This article gives a preliminary analysis of the impact of application of horizontal drilling and production techniques on the economy of offshore reservoir developments.

If we consider wells with a medium and long radius of curvature ensuring horizontal drilling in reservoirs with horizontal sections of greater than 300 m (1000 ft), theoretical research shows that flow ratios of four or more can be obtained in practice in practically all reservoirs, provided they are vertically permeable and no more than 60 m (200 ft) thick. These theoretical results agree well with what is observed in the field.

Analysis of the data available on horizontal drillings performed so far shows that offshore, the cost per metre drilled in a horizontal well tends with experience towards the cost per metre drilled in a conventional well. The excess cost of a horizontal well is essentially due to the greater length drilled.

Offshore, the capital and operating costs bear an increasing relationship to the number of wells and production level. From a model of these costs based on 28 projects in the North Sea, the impact of replacing conventional wells with horizontal wells was studied. In the case of complete development, the reduction in the number of wells for the same production flow enables the technical cost of the oil to be decreased by 2 to 8 dollars per barrel, depending on the case. The parameters of importance are firstly, the ratio of the flowrate of the horizontal well to the flowrate of the conventional well, secondly the ratio of the cost of drilling to the total cost and thirdly the flowrate of the conventional reference well.

Cases of application yielding the greatest savings are those where the share of drilling costs out of the total cost is high, over 25 % and cases where the flowrate of conventional wells is low, below 2000 Bopd.
An Appraisal of Continuous Vs Intermittent Treatment of Water Injection Systems
Authors: Wright Charles C.
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 discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

A detailed appraisal is made of the chemical and physical principles involved in continuous chemical treatment of a water system, vs intermittent treatment of a water system.

The paper covers in detail the properties of the several chemical treatments given water systems and relates how these influence the mode of treatment of a water system and the resultant efficiency of the treatment.

Field evidence is presented to show how these factors bear on the mode of treatment.

Recommendations are made to govern several definable conditions.

Introduction

The use of intermittent chemical treatment as compared with continuous chemical treatment offers the hope of substantial cost savings. Fig. l shows the ratio of amount of chemical required for continuous feed as compared with intermittent feed when the equal concentrations are used.

Intermittent treatment cannot be applied indiscriminately, however, as there are some principles which, if violated will cause the treatment to be ineffective.

Principle No. 1

Intermittent treatment cannot be successfully applied where the chemical used has no residual effect and the mechanism being treated is present continuously.

Example A

The incoming water contains 2.5 mg/liter dissolved oxygen. Catalyzed sodium sulfite is being used as an oxygen scavenger. The catalyzed sodium sulfite must be fed continuously as it is used to react with the dissolved oxygen to remove it from the water. Corrosion will result whenever the catalyzed sodium sulfite feed is interrupted.

Example B

The incoming water is unstable and will deposit calcium carbonate scale as it warms up on its way down the injection well tubing. Hexametaphosphate must be fed continuously as it is used as a crystal poisoner to prevent the calcium carbonate from forming an adherent scale. Scale formation will result whenever the hexametaphosphate feed is interrupted.
Leak Detection Using a Nitrogen — Helium Gas System
Authors: Cooper R. E.
Published: December 2007

A combined nitrogen purge and helium leak-detection system has been developed to safely pressure test and commission oil and gas process equipment. The system is able to detect leaks of a much lower magnitude than conventional leak detection systems and it offers several advantages over conventional hydrostatic testing. Inert nitrogen gas (used as the pressurizing medium) also safely purges the process system of oxygen and flammable gases, while helium in trace amounts provides a means of detecting leaks as low as 0.03 m3/yr. A mass spectrometer is used to detect extremely low levels of the helium detector gas.

Once the process equipment has been certified as leak free, a low pressure nitrogen blanklet can be left in the system. Gas process equipment also can be operated under simulated working conditions using nitrogen. This has proved beneficial for instrument calibration and training purposes.
The Production Performance of the Water-Dissolved Natural Gas Reservoir
Authors: Akibayashi S. , Zhou P.
Published: December 2007

A numerical two-phase model is developed to simulate the production performance of the Hobara-type water-dissolved natural gas reservoir in Japan. By using this model, the behavior of producing gas-water ratio and reservoir pressure is matched successfully. This paper also presents some calculation examples by the matched model which describe the effect of permeability, relative permeability and initial gas saturation on the above production performance
Use of Compositional Simulation in the Management of Arun Gas Condensate Reservoir
Authors: Sutan-Assin T. , Rastogi S. C. , Abdullah M. , Hidayat D. , Bette S. , Heineman R. F.
Published: December 2007

This paper describes the simulation of the Arun gas condensate reservoir using Mobil's fully compositional simulator, COSMOS (Compositional System Mobil Oil Simulator). The reservoir is a Miocene carbonate reef complex which occurs at a depth of approximately 10,000 feet, and is up to 1.000 feet thick in some areas. The Arun reservoir is a ccmpositionally dynamic system. The purpose of this simulation study was to predict future reservoir performance under various demand scenarios and optimize gas and NGL recovery. The simulation model utilizes the Peng-Robinson equation of state to account for the compositionally dynamic behavior of the reservoir in predictions of future performance; The equation of state was modified by Mobil to incorporate-special features for Arun such as water vaporization in the reservoir under high temperature conditions.

A significant amount of time was spent on the geologic description of the field and initial data preparation, which contributed to a good match of the historical data. The simulation model will serve as a reservoir, management and planning tool to evaluate future operating strategies in the field. The technology presented in this paper is applicable to the management of other gas condensate reservoirs which exhibit physical phenomena such as retrograde condensation, revaporization, and water vaporization.
Enhancing the Evaluation of PVT Data
Authors: Drohm J. K. , Goldthorpe W. H. , Trengove R.
Published: December 2007

A procedure for evaluating the quality and consistency of PVT data is presented. This procedure uses the material balance and the associated error analysis for investigating experimental accuracy, and to identify the sources of erratic data. The use of this method to 'correct' erratic data is illustrated for a near-critical or volatile oil and a gas-condensate.
Environmental Impact Assessment of the Dulang Oilfield Development Project
Authors: Hasan M. N. , Ismail M. Y.
Published: December 2007

An environmental impact assessment (EIA) of the Dulang Oilfield Development Project, was conducted to determine whether the project could proceed in a safe and environmentally acceptable manner. This is the first EIA for an offshore oilfield in Malaysian waters, and was conducted in anticipation of the Environmental Quality (Prescribed Activities) (Environmental Impact Assessment Order (1987)) which requires an EIA to be conducted for major oil and gas field development projects.
Drain System Modifications Enhance Platform Safety
Authors: Wong J.
Published: December 2007

The paper describes EPMI's efforts to eliminate potentially catastrophic hydrocarbon liquid and gas discharge from the open drains of its platforms located offshore Peninsular Malaysia in the South China Sea.

The hydrocarbon discharges were largely precipitated by equipment failure and related events but were made physically possible by the use of a cannon discharge caisson by both the open and pressured drain systems.

For platforms containing major processing equipment, the modifications to separate the open drains from the pressured drains involve the installation of a second drain caisson. For other platforms, the systems were separated by returning the pressure drains discharge to the process stream. As a result of the. described modifications, high pressure crude clumped to the drains even at very high flowrates cannot result in hydrocarbons to be discharged from the open drains.

All EPMI platforms have been modified and the installed systems are operating satisfactorily. EPMI now requires the complete separation of the pressured drains from the open drains in all its offshore installations..
Oil Spill Contingency Planning
Authors: Kip S. H.
Published: December 2007

Oil spill contingency planning is an essential feature required in present day activities involving oil and gas exploration, production and transportation. A well thought out Contingency Plan will not only eliminate or minimise the sense of panic, normally associated with oil spill emergency, but also can minimise damage and cost involved.

Simply put, oil spill contingency planning is a process of predetermining a response to an oil spill emergency. The process of preparing a contingency plan varies but the final plan is normally produced into a document, to be followed in an oil spill emergency. With this document prepared and agreed by all concerned parties, the approach and response to an oil spill should be more organised. It is also generally accepted that an organisation with the necessary contingency plan in place is better prepared to handle an emergency that one without a contingency plan.

Oil spill contingency planning is a feature of Shell Group policy. Sarawak Shell Berhad (SSB)/Sabah Shell Petroleum Company Limited (SSPC) produced an Oil Spill Contingency Plan in 1978 which has undergone a number of modifications and updates. Drills and exercises are also conducted with a view to improve the company preparedness to tackle oil spill emergencies.
Insights Into Natural Gas Production From Low-Permeability Reservoirs
Authors: Northrop D. A.
Published: December 2007

Insights have been gained into natural gas production from low permeability sandstone reservoirs in the western United States as a result of the U.S. Department of Energy's Multiwell Experiment (MWX). Three wells, between 110 and 215ft (34–66m) apart at depth, have been drilled at a site southwest of Rifle, Colorado, in the Piceance Basin, where the Cretaceous-age Mesaverde lies at a depth of 4,000 to 8,250ft (1220-2520m). Activities have been conducted in the lowermost Corcoran-Cozzette marine sandstones and in the overlying paludal, coastal, and fluvial nonmarine intervals. Insights include: (1) the depositional environment controls reservoir morphology, size, internal structure, and natural fracturing; thus, it must be discerned in order to optimize completions and interpret reservoir performance; (2) natural fractures, even if small and mineralized, are the dominant production mechanism in these, and probably most other, very tight reservoirs; (3) breakdowns and extended cleanup and test times are required for accurate reservoir assessment; (4) effectiveness of hydraulic fracturing appears limited by an anisotropic natural fracture system, high fracturing pressures, accelerated leakoff, and damage to the natural fracture system; and (5) in situ stress behavior varies with depth and lithology, is complex, and significantly affects stimulation and gas production.
Innovative Flexible Interior Gas Distribution Systems
Authors: Torbin R. N. , Wilkey M. , Belkus P.
Published: December 2007

The Gas Research Institute (GRI) is funding research to investigate alternative gas piping technologies which can make gas service as easy to install as electric service. The semirigid tubing systems being evaluated are soft copper tubing and a Japanese product, corrugated stainless steel tubing (CSST). Both use mechanical fittings and are designed to operate using either traditional low pressure (8 in. of water column (WC)) or a special hybrid pressure (2 psi and 8 in. WC) approach. This research has been conducted at several different single family and multifamily buildings located throughout the United States.

Results from these sites indicate that regardless of the building type, semirigid tubing systems can be installed in less time and usually at lower cost than conventional steel pipe systems. The labor savings vary between 30 and 70 percent, while the cost savings vary between 10 and 50 percent. The use of these semirigid tubing systems also makes a decentralized gas distribution system more viable.
The Polyethylene Pipes Gas Distribution Network in France: Choice of a System Already of Long Standing, but the Right Choice
Authors: Fallou J. , Bardin J-C.
Published: December 2007

Following research in its laboratories and implementation on experimental sites, GAZ DE FRANCE authorized polyethylene service pipes to be used in 1974 and polyethylene pipelines to be used on its network in 1979. At the same time, it was decided to authorize electrofusion as the only assembly method, with the intention to develop the corresponding technique gradually as the possibilities and need evolved in accordance with GAZ DE FRANCE specifications. In recent years, most new extensions and renovations of the GAZ DE FRANCE network have applied a coherent "Electrowelded Polyethylene System" (E.P.S.), thus gradually converting the distribution network to polyethylene.

After describing the main characteristics and advantages of this "Electrowelded Polyethylene System" gas technique, the authors emphasize two salient features of the system: –automatic welding,–use of very long pipes (several hundred meters) both for renovation and new extensions of the network.

The drum-wound polyethylene tubes can be laid by a trencher at a speed of up to 300 meters per hour for laying network extensions. For renovations, lengths of 80, 100 or more meters can be inserted in the former low pressure pipeline requiring only minimum excavation work.

It should be noted that the "Electrowelded Polyethylene System" comprises all the necessary tools: tube cutters, positioners, scrapers, welding set, drums, road-trailers, drum-carriers, trenchers, winches and pulling accessories. It also includes all the accessories of the network and the repair and build-up techniques and equipment.

Implementation of the E.P.S. gas technology is of direct assistance in converting the GAZ DE FRANCE former low pressure gas distribution network to the "medium pressure B" 4 bar distribution pressure enabling the customers to be supplied both more reliably and at lower cost.
Computerized Engine Monitoring
Authors: Peterson K. A.
Published: December 2007

Low cost personal computers have been successfully applied to the task of monitoring and recording data points from gas compressor engines in a gas processing plant. The resultant benefits have included: *Enhanced engine monitoring,*Removal of the operator from the engine room environment without a loss in the productivity of the operation,*Reduced maintenance efforts in diagnosing and trouble shooting, and*Reduced operator man power and man hours.

Utilizing a remotely mounted personal computer and terminal, an operator can access and monitor one or more points on an engine or retrieve data stored on a particular engine up to and including the previous thirty (30) days. Displays at the operator's terminal are custom tailored to specific operating demands and include both real time (updated on 10 second intervals) and calculated values. Operating trends and performance are graphed so that developing problems can be predicted and compressor downtime scheduled.
Field Results of Pulse Tests in a Highly Anisotropic Dual-Porosity Gas Reservoir
Authors: Grabowski M. A. , Locke C. D , Saradji B. , Feiler J. , Yost A. B.
Published: December 2007

Results of a highly-instrumented multiple well field test to characterize a dual-porosity gas reservoir are presented. The field test consisted of two pulse tests between four wells drilled into a naturally fractured, highly anisotropic gas reservoir. The test procedure utilized constant flow rate pulses in the production wells and bottomhole shut-off techniques in the observation wells to minimize well bore storage distortion of the pressure responses.

Field test results were analyzed using conventional pulse test analysis techniques. Coring and geophysical logging data were used to further characterize the reservoir within the test area and to provide porosity and permeability data for the analysis. The tests confirmed the continuity of the reservoir, provided estimates of permeability and porosity, and provided Insight into requirements for conducting pulse tests in reservoirs having similar characteristics.