bluuebunny/crossref_metadata_2025 huggingface dataset:
A Dual Gas Tracer Technique for Determining Trapped Gas Saturation During Steady Foam Flow in Porous Media
Authors: Radke C. J. , Gillis J. V.
Published: December 2007

Foam is a possible mobility control agent for effective oil displacement from reservoirs. Thus, it is important to understand the mechanisms by which foam flows in porous media. Micromodel studies and prior gas-phase tracer experiments show that a significant fraction of the gas in a foam exists as trapped bubbles which, therefore, have a major impact on the flow resistance. Unfortunately, in the tracer experiments performed to date, partitioning of the tracer into the trapped gas has not been accounted for. Currently, only qualitative information is available on the actual amounts of trapped gas.

To overcome these limitations and obtain quantitative measurements of trapped gas saturations, we have developed a unique experimental apparatus employing dual gas tracers. During steady foam flow in a porous medium, dilute sulfur hexafluoride (SF6) and methane (CH4) tracers in a nitrogen carrier are injected, and the effluent concentration is monitored by gas chromatography. The measured tracer histories are fit to a simple mass transfer model which describes any partitioning between the mobil and trapped foam phases. Tracer effluent concentrations predicted by the model are strongly influenced by the solubility of each tracer in the liquid phase. This behavior is observed in the experimental histories as well. Hence, multiple gas tracers provide a discriminating assessment of trapped gas saturation during foam flow through porous media.

New trapped gas saturations are reported for an aqueous C14-16α-olefin sulfonate foamer solution and nitrogen flowing through a 2.3-μm2 fired Berea sandstone at 105 Pa (1 atm) back pressure and at room temperature. Total superficial velocities range from 0.4 to 4 m/day while inlet gas fractional flows are varied from 0.8 to 1.0. We find large fractions of trapped gas between 80 and almost 100% depending on the particular flow conditions. The importance of trapped gas to understanding foam-flow behavior is again confirmed.
An Artificial Neural Network Approach to Identify the Well Test Interpretation Model: Applications
Authors: Al-Kaabi A. U. , Lee W. J.
Published: December 2007

The objective of this paper is to present the application of a new approach to identify a preliminary well test interpretation model from derivative plot data. Our approach is based on artificial neural networks technology.

In this approach, a neural nets simulator which employs backpropagation as the learning algorithm is trained on representative examples of derivative plots for a wide range of well test interpretation models. The trained nets are then used to identify the well test interpretation model from new well tests.

In this paper we show that using artificial neural networks technology is a significant improvement over pattern recognition techniques currently used (e.g., syntactic pattern recognition) in well test interpretation. Artificial neural networks have the ability to generalize their understanding of the pattern recognition space they are taught to identify. This implies that they can identify patterns from incomplete and distorted data. This ability is very useful when dealing with well tests which often have incomplete and noisy data. Moreover, artificial neural networks eliminate the need for elaborate data preparation (e.g., smoothing, segmenting, and symbolic transformation) and they do not require writing complex rules to identify a pattern. Artificial neural networks eliminate the need for using rules by automatically building an internal understanding of the pattern recognition space in the form of weights that describe the strength of the connections between the net processing units.

The paper illustrates the application of this new approach with a field example. The mathematical derivation and implementation of this approach can be found in Ref. 1.
Transient Pressure Behavior and Formation Damage Evolution of Wells During Matrix-Acidizing Operations
Authors: Rodriguez F. , Sanchez-B. J. M. , Cinco-Ley H.
Published: December 2007

The transient pressure response and the evolution of formation damage of a well during a matrix-acidizing operation, performed at constant injection rate, is studied in this paper. Solutions are derived from a novel fully-implicit numerical model which simulates the mechanics of a matrix-acidizing process along with the mechanics of compressible flow in a porous media. The dynamic changes of permeability and porosity due to dissolution of up to two mineral species are considered in the reservoir flow equation. A damaged zone with petrophysical properties and mineral content different from the rest of the reservoir is included; the injection of a batch of inert fluid prior to the acid is also accounted for.

It is found that the pressure behavior and the evolution of formation damage during acidization depend mainly on the acid capacity number, NAc, the Damköhler number, Npa, the initial formation damage, S0, and the radius of the damaged zone, rsD). Typically, the early time presure response of an acidized well might show a semilog straight line of slope 1.151, if NAC and NDa are small enough. As formation damage is being removed, there is a continuous decrease in the slope of the pwD vs tD curve which eventually takes on negative values. At later times, when formation damage is removed, all curves converge to the stimulation with no damage case and positive slope values are reassumed. Major benefits of acidization are found with large s0 and small rsD. Large Damköhler numbers seem to perform better al early st imulation times and worst afterwards, suggesting that variable injection rates could yield the best stimulation results. Acid capacity number was found to have a major effect over pwD and formation damage evolution.
An Application of Geostatistical Methods for Risk Analysis in Reservoir Management
Authors: Srivastava R. M.
Published: December 2007

A case study is presented of risk analysis for a reservoir in which gas injection is used to enhance oil recovery. Geostatistics is used to build a procedure for addressing the question of how much gas should be injected. Through the use of indicator simulation, this procedure incorporates not only the quantitative information available from well logs, but also the qualitative information available from a geologic model of the reservoir. The use of loss functions enables the decision-maker to incorporate the economic parameters that affect the enhanced oil recovery procedure.
Pressure Buildup Test Results From Horizontal Wells in the Pearsall Field of the Austin Chalk
Authors: Lichtenberger G. J.
Published: December 2007

This paper presents the results and representative data sets of pressure transient tests on horizontal wells in the Pearsall Field of the Austin Chalk. The data trends indicated possible early time radial flow, largely obscured by wellbore storage, followed by a strongly developed linear flow period. On tests of adequate length this is followed by a multiple porosity transition and a return to linear flow. The data was interpreted in terms of a pseudosteady state dual porosity flow model for the Austin Chalk. The fracture system permeability was estimated to be in the range of 0.5 to 10 md, the dual porosity storativity ratio was found to be between 0.1 and 0.01, while the interporosity flow coefficient had values near IE-07. The net thickness drained by the wells was determined to be between 100 and 400 ft, depending on the well tested. The abnormally large observed wellbore storage coefficients correlate with well productivity and are considered to be indicators of the fracture intensity.
A New Approach to the Prediction of Slug Frequency
Authors: Hill T. J. , Wood D. G.
Published: December 2007

The design of crude oil production systems involving the pipelining of unseparated reservoir fluids requires a detailed understanding of multiphase flow phenomena. Slug flow in particular may cause undesirable process upsets if the separation and processing facilities are not designed to handle the resultant gas and liquid flowrate variations.

Slug characteristics, primarily length, holdup and frequency, cannot be adequately predicted by existing empirical correlations. Mechanistic models are more satisfactory if the measured slug frequency is used as an input. However, existing methods for predicting slug frequencies are also unsatisfactory.

BP have collected a large database on slug flow characteristics in both low pressure test rigs and field production flowlines. From this database BP have developed an improved method for the prediction of slug frequency. This method correlates slug frequency against the two parameters which appear from test rig observations to be the most important in the initial formation of slugs from a stratified flow. These parameters are the liquid holdup in the stratified film at the start of the line, and the gas-liquid slip velocity. The results indicate a much improved comparison with the data. The phenomenological approach to the correlation development gives increased confidence of its applicability to conditions outside the range of data from which it was developed.
Use of Field Data in the Analysis of the Influence of Proppants on Apparent Fracturing Fluid Viscosity
Authors: Jennings A. R.
Published: December 2007

Fracturing fluid viscosity has an important influence on the outcome of any hydraulic fracturing treatment. Much work has been done on the effect of sand or particle concentration on the viscosity of Newtonian fluids. Work concerning the effects of proppant concentration on the apparent viscosity of non-Newtonian fracturing fluids is now beginning to appear in the literature. Several correlations involving the effects of proppant or particle concentration in non-Newtonian fluids have been presented recently.1–5

This work presents an assessment of influence of proppant on fracturing fluid viscosity using the friction pressure properties of sand-laden non-Newtonian fracturing fluid compared to the friction pressure of the fluid without proppant. For this presentation, the premise is offered that viscosity effects due to the suspended particles in non-Newtonian fluids'should be correlatable when comparing fluid pressure behavior of these fluids in turbulent flow.

Correlations have been worked out to describe the effects of sand concentration on effective fluid viscosity. These results compare favorably to the results obtained by other investigators addressing the problem using different techniques.
Effects of Fracture Fluid Invasion on Cleanup Behavior and Pressure Buildup Analysis
Authors: Montgomery K. T. , Holditch S. A. , Berthelot J. M.
Published: December 2007

A hydraulic fracture treatment is the most common method used to stimulate the gas flow rate of a well completed in a low permeability gas reservoir. Hydraulic fracturing is accomplished by pumping a proppant laden fluid into the formation at high injection rates.' Once the minimum principle stress in the formation is overcome, a fracture is induced and begins to grow. The vertical fracture will continue to grow until pumping is stopped. After the fracture treatment, fracture fluid will leak off and imbibe into the formation around the fracture as the fracture closes. After the fracture has closed, the well will be placed on production in order to clean up the fracture fluid around the fracture and begin producing gas.

Prior to performing a hydraulic fracture treatment, a complete reservoir description should be developed by the engineer and geologist. The reservoir description should include properties such as formation permeability, porosity, net pay, reservoir pressure, skin factor, and other information needed to properly describe oil and gas flow from the reservoir.2,3

In addition, the mechanical properties of the formation layers above and below the productive zone should be evaluated. The mechanical properties are needed to compute the estimated shape and dimensions of the hydraulic fracture that will be created. After the reservoir description has been completed, the hydraulic fracture treatment can be designed and pumped. During the fracture treatment design, the engineer should optimize the fracture length and the fracture conductivity based upon the pre-fracture reservoir description. In order to improve the productivity of future wells, each existing well should be analyzed after the fracture treatment to determine how to improve the fracture treatment design.2,3
Gas-Liquid Two-Phase Flow in Pipelines
Authors: El-Oun Z.
Published: December 2007

A combined theoretical and experimental investigation to study the behaviour and characteristics of gas-liquid two-phase flow in horizontal pipelines is described in this paper.

A simple theoretical model was developed to provide predictions of liquid hold-up in equilibrium stratified two-phase flow regimes and transition boundaries into slug flow. In order to calculate the liquid hold-up, the pressure drop equations were considered. The pressure drops in the two phases together with the shear stresses at the walls and interface were solved numerically. The criterion employed for predicting the onset of slug formation is wave instabiltiy which occurs when the wave velocity is imaginary.

The experimental study was conducted over a wide range of flow conditions to investigate pressure loss, liquid hold-up, flow pattern transitions and slug/bubble characteristics. The results presented in the paper are only flow pattern transitions and slug/bubble characteristics. The experiments were conducted on 0.2 and 0.4m, diameter, 400m long loops at BHRA for a range of superficial air and water velocitie's up to VSG = 24m/s and VSL = 2n/s.

The agreement between the experimental observations and the predictions of the transition into slug flow is considered excellent. Based on the average experimental data generated from these loops and from a separate study conducted on different fluids and pipelines, various empirical correlations for calculating the slug/bubble characteristics have been developed. Comparisons were also made between the measurements and current design methods, thus stating their range/limitations of applicability.
Phase Distribution During Gas/Liquid Flow Through Horizontal Dividing T Junctions
Authors: Hart J. , Hamersma P. J. , Fortuin J. M. H.
Published: December 2007

A model has been developed to the predict route preference of condensate at T junctions in gas transportation pipelines. This so-called 'Double Stream Model' has been derived from the steady-state macroscopic mechanical energy balance (Bernoulli equation), applied to the 'inlet-to-run' stream and the 'inlet-to-branch' stream of both the gas phase and the liquid phase.

The theory is applicable to the stratified-wavy and annular flow regimes, provided the liquid holdup 𝛜L< 0.06. The model has been verified with experimental results carried out in our Chemical Engineering Department, using air-water flow in a horizontal tube with a horizontal tee (D1 = D2=D3= 0.051 m), and with experimental results from Institutes in the USA and Canada.

Results predicted with the Double Stream Model are in good agreement with experimental results, obtained with regular (D1=D2=D3) and reduced (D3<D1) T junctions.
Enhanced NGL Recovery in the Arun Field Expander Plant Using a Low-Pressure Absorber for Maximizing Propane Recovery
Authors: Berini D. L. , Widjojo T.
Published: December 2007

This study compares the propane recovery efficiency of an expander plant using a low- pressure absorber with that of a conventional expander plant. By optimizing the reflux rate to the low-pressure absorber, propane recoveries close to 90% are achievable. Actual operating data matches very closely with computer simulation predictions.

This paper relates specifically to the Arun Field NGL extraction facilities which are designed to process 1,000 MMscf/D [28,317 103m3/d] of feed gas.
Design, Development, and Field Test of a True Vapor Pressure Analyzer
Authors: Reed D. B. , Monday W. L. , Chou K. , Ogren W. E.
Published: December 2007

This paper describes the development and testing phase of an on-line device to measure the True Vapor Pressure (TVP) of any liquid, but with particular application to hydrocarbons including both crude oil and refined products. The method is based on classical thermodynamic principles, and measures the TVP of the fluid in a time frame of minutes. The advantages of measuring TVP rather than Reid Vapor Pressure will be discussed, and supporting data presented. The paper describes the principle of operation, the development of the system into a field deployable device, presents results of laboratory and field tests, and describes some potential applications.
Artificial Neural Networks for Identification of Beam Pump Dynamometer Load Cards
Authors: Rogers J. D. , Guffey C. G. , Oldham W. J. B.
Published: December 2007

1 ABSTRACT

The oiL industry, spurred by the need for cost efficiency and the loss of experts in technical areas, has begun to apply Artificial Intelligence or Expert systems. This paper details the use of a pattern recognition scheme using Fourier Descriptors and a Neural Network model to develop an Artificial Intelligence system to analyze and classify beam pumping unit dynamometer diagrams.
Hydrocyclone Produced Water Treatment for Offshore Developments
Authors: Choi M. S.
Published: December 2007

Ever increasing water production and more stringent environmental standards have driven up the cost of produced water disposal. What was once a small consider-ation in the design of production facili-ties has become a high profile and costly component of offshore production projects.The large space and weight requirement for conventional produced water treatment (PWT) systems (skim tanks,CPI's and flotation cells) could have a large nega-tive impact on the overall economics of a deep water development.

Recent advances in static hydrocyclone technology for PWT has added an attractive alternative to conventional systems.In 1985,Conoco installed a small hydrocyclone PWT system on the Murchison platform in the North Sea. The success of that first pilot system has lead to the expanded use of the technology in other locations in the North Sea and the Arabian Gulf. With the experience gained from the design, testing and ex-tended operation of these systems, Conoco has developed a high level of confidence in defining the capabilities and limits of hydrocyclone PWT systems, and the economic benefits possible when applied to offshore projects.
Analysis of Operational Practices and Performance of Selected Gulf of Mexico Operators
Authors: Bolin W. D. , Brienen J. W. , Morgan R. L. , Pyles S. R.
Published: December 2007

In 1989, Oryx Energy Company conducted personal interview surveys with 13 Gulf of Mexico operators to quantify various operating practices, philosophies, and techniques. Production statis-tics and economic indicators were also compiled. The companies surveyed included Amoco Production Company, Arco Oil and Gas Company, Conoco Inc., Forest Oil Corporation, Kerr McGee Corporation, Marathon Oil Company, Oryx Energy Company, Pennzoil Exploration & Production Company, Samedan Oil Corporation, Unocal, and others.

As a result of analyzing the information, Oryx undertook a major restructuring of its Gulf of Mexico operation. In addition, other survey participants have started organizational and/or operational changes of their own.
Operation and Utilization of Hydraulic-Actuated Service Tools for Reeled Tubing
Authors: Fowler S. H. , Pleasants C. W.
Published: December 2007

The advent of highly deviated and horizontal well completions has created the need for a new line of service tools that do not rely upon gravity for the setting and retrieving of downhole tools. When using reeled tubing in downhole applications, in particular highly deviated or horizontal wells, frictional drag can limit the available forces required to set and pull flow controls, shift sleeves, shear pins, etc1 As such, tools are needed that take advantage of the pressure and flow capabilities of the reeled tubing to create an efficient system for servicing highly deviated and horizontal wells in addition to conventional vertical wellbores.
Inflow Performance Relationships for Solution-Gas-Drive Slanted/Horizontal Wells
Authors: Cheng A. M.
Published: December 2007

Since 1968, the Vogel equation has been used extensively and successfully for analyzing the inflow performance relationship (IPR) of flowing oil wells under solution-gas drive. Oil well productivity can be rapidly estimated by using the Vogel IPR curve and well outflow performance. However, the Vogel curve was originally developed for conventional vertical wells and may not be valid for slanted and horizontal wells. The development of IPR’s for slanted and horizontal wells by using a vertical/horizontal/slanted well reservoir simulator is presented. Several important results were observed. First, the IPR’s for slanted and horizontal wells are similar to the parabolic behavior of the Vogel IPR curve. Second, IPR data generated for slanted wells by using the Vogel curve can differ as much as 22% from that of the new IPR data and 27% for horizontal wells. Third, the right curvature shift of the Vogel curve for slanted and horizontal wells indicates that these wells are more efficient producers than vertical wells from a subsurface fluid flow viewpoint. Fourth, a minimum slant angle of 45 degrees is required to increase oil productivity by 50% over that of a vertical well. A slant angle of 60 degrees or greater can increase oil productivity more than two times that of a vertical well. The newly developed IPR data are compared with existing empirical and field data. Several application examples are presented to illustrate the use of these IPR’s to predict slanted/horizontal well productivity.
Influence of Matrix Shrinkage and Compressibility on Gas Production From Coalbed Methane Reservoirs
Authors: Harpalani S. , Schraufnagel R. A.
Published: December 2007

The effect of methane desorption on gas flow through coal was investigated. Adsorption/desorption isotherms were established for coal samples. Permeability of cylindrical samples to different gases was measured at simulated in-situ conditions in a triaxial stress field. Gas pressure-permeability-desorption relationship was established for helium, methane and carbon dioxide. Related experiments measured coal compressibility, and volumetric changes of coal matrix with methane adsorption and desorption.

The hypothesis that desorption of methane shrinks coal matrix, and results in increased permeability was confirmed. The increase in matrix permeability with reduction in pressure from 1000 psi to atmospheric was highest for carbon dioxide (the most adsorptive gas), on the order of a factor of five for methane, and non-existent for helium. The corresponding volumetric shrinkage of coal matrix on desorption of methane was 0.6%. When measured values of compressibility and shrinkage were used as input parameters into a reservoir simulation model, 60% more gas was produced over a five year period.
Material Balance Techniques for Coal Seam and Devonian Shale Gas Reservoirs
Authors: King G. R.
Published: December 2007

This paper presents the development of two material balance methods for unconventional gas reservoirs. One method is appropriate for estimating gas-in-place while the second is appropriate for making future reservoir predictions. These techniques differ from the material balance methods for conventional gas reservoirs, in that, the effects of adsorbed gas are included. Both methods are developed using the assumptions traditionally associated with the material balance approach. For estimating original gas-in-place, the additional assumption of equilibrium between the free and adsorbed gas phases is required (ie., gas desorption is assumed to be strictly pressure dependent). Simplified forms of this generalized equation corresponding to special cases (volumetric reservoirs, etc.) are also presented. No additional simplifying assumptions are required for making future reservoir predictions.

The results of both methods are compared to those of a rigorous finite-difference simulator developed specifically for unconventional gas reservoirs. These comparisons are made to determine the effects of all assumptions and the magnitude of these effects.

Due to the assumption of equilibrium, the first approach is appropriate for shut-in wells or flowing wells in reservoirs undergoing rapid desorption. The assumption of rapid desorption corresponds to reservoirs with a high natural fracture density (small primary-porosity matrix blocks) or with a high diffusion coefficient.

It is believed that the techniques presented in this paper provide basic tools currently unavailable to engineers working with unconventional gas reservoirs.
Enhanced Coalbed Methane Recovery
Authors: Puri R. , Yee D.
Published: December 2007

At present, coalbed methane is being recovered by means of reservoir pressure depletion. While this method is simple and effective, it is not efficient. Reduction in reservoir pressure deprives the fluids of the energy necessary to flow to the wellbore. Furthermore, there is a practical and economic limit on the extent to which reservoir pressure can be reduced. It is estimated that reservoir pressure depletion strategy of coalbed methane production will permit the recovery of 50% or less of the gas-in-place.

This paper discusses an alternate method of coalbed methane recovery which consists of nitrogen flooding a coal seam. Lab research has shown that essentially all methane sorbed on coal can be stripped by nitrogen without necessarily reducing the total system pressure. That is, methane desorption from coal is achieved by reducing the partial pressure of methane rather than merely the total pressure. Lab and modeling results are presented to demonstrate how nitrogen injection in coal can accelerate methane production rates and enhance reserves. Scoping process economics of enhanced coalbed methane production also appear to be attractive.
Validation of 3D Coalbed Simulators
Authors: Paul G. W. , Sawyer W. K. , Dean R. H.
Published: December 2007

Simulation results for three coal seam gas problems are compared for models developed by ICF Resources Inc. and ARCO Oil and Gas Company. Excellent agreement between the two simulators is obtained.
Future Prospects of Deep Delaware Basin Exploration
Authors: Zimmerman James B. , Long Laddie F.
Published: December 2007

American Institute of Mining, Metallurgical and Petroleum Engineers Inc.

The discussions and postulations in this paper are confined to formations of Wolfcamp paper are confined to formations of Wolfcamp age and older. The exploration of the Delaware basin has not followed the normal pattern of basin development. Expensive pattern of basin development. Expensive drilling costs, carbon-dioxide gas distribution, the uncertainty of future gas prices, lack of deep subsurface data, and difficulty with seismic interpretations have caused an erratic development. In addition, the Delaware basin has had to share the exploration dollar with the Val Verde basin. The first significant deep gas reserves were proven in the Val Verde basin and it was nearly 10 years before any promising reserves were found in the Delaware basin. The authors have combined data on the Delaware and Val Verde basins in order to obtain a better development history. Based on reserve prediction methods as developed by Hendricks and Moore, it is estimated that approximately 100 trillion cu ft of gas in place ultimately will be discovered in the place ultimately will be discovered in the Delaware-Val Verde basins.

In all probability, future exploration in the Delaware basin will continue to be spasmodic. Most of the new drilling in the immediate future apparently will be concentrated in the Val Verde basin once again. Although the southern part of the Delaware basin undoubtedly will continue to receive its share of exploration interest for a number of years, the northern portion offers the larger area with deep gas potential still relatively untested. It is logical to expect this area to receive its share of attention in future years.

Introduction

The future exploration prospects of any geological basin are difficult, at best, to evaluate, and pertinent geological knowledge of the area is essential. A review of the methods used by recognized authorities reveals that the best predictions are based on either a long history of reserves discovered or cumulative production. A production history of the production. A production history of the Delaware basin is almost nonexistent since most of the giant gas discoveries still are awaiting pipeline connections. By industry standards, a pipeline connections. By industry standards, a giant discovery contains over 1 trillion cu ft of gas. A comparison of discovered reserves by year of discovery does not make a satisfactory historical plot because the giant discoveries fall in a recent five-year period.

To obtain a better history, the authors have combined the Val Verde and Delaware basins, since both basins have the same geological characteristics and should be considered joint in any study of this nature.

This study is confined to reserves in formations of Wolfcamp age and older.
Study of Hydrate Dissociation by Methanol and Glycol Injection
Authors: Sira J. H. , Patil S. L. , Kamath V. A.
Published: December 2007

Formation of gas hydrates have been known to cause severe problems of blockages in natural gas pipelines, wellbores and natural gas processing units. Methanol and glycols are commonly used as hydrate inhibitors to control or prevent formation of gas hydrates, due to their ability to lower hydrate formation (or dissociation) temperatures considerably. For the same reason, they are very effective hydrate dissociation stimulants for enhancing gas production from hydrate reservoirs as demonstrated by a field study in the Messoyakha gas hydrate reservoir of the Soviet Union (Makogon, 1981). Effect of these hydrate inhibitors on the thermodynamic phase behavior of gas hydrates has been well established, however, no experimental data exist on effect of inhibitors on the rate of hydrate formation or dissociation. Hence, the current methods of prevention of hydrate formation by inhibitors have relied upon the thermodynamic data rather than kinetic data.

In this study, the characteristics of hydrate dissociation process during methanol and ethylene glycol injection were investigated. After formation of methane hydrates in the synthetic cores, hydrates were dissociated by injection of inhibitor solution of known initial concentration, at a constant rate. The pressure was held constant during dissociation and gas production, inhibitor solution temperature and dissociating hydrate front position were monitored continuously. Experimental results show that the instantaneous rate of hydrate dissociation is function of inhibitor concentration, inhibitor injection rate, pressure, temperature of inhibitor solution and hydrate-inhibitor interfacial (contact) area. Based upon the unsteady state dissociation data, empirical correlations for the rate of hydrate dissociation in presence of inhibitors are developed. The correlations can be used to compute the degree of enhancement in the rate of hydrate dissociation by inhibitors in applications such as hydrate prevention or production of natural gas from hydrates.
Reduction of Residual Oil Content in Produced Water at Offshore Gas Production Platform P/6A
Authors: op ten Noort F. J. , Etten J. P. , Donders R. S.
Published: December 2007

The produced water on the P/6-A gas producing contains a residual amount of oil after primary separation treatment. This oil consists of finely dispersed aliphatic hydrocarbons with extremely small particle sizes and aromatic hydrocarbons dissolved in the water. Due to the relatively high ratio of aromatics to aliphatics, the aliphatic hydrocarbon droplets tend to remain in suspension. This renders it difficult to separate out the dispersed hydrocarbons by means of gravity and coalescence. To comply with the prevailing regulation of 40 mg/liter of oil-in-water, secondary means of oil· in-water reduction have been explored. Several technologies have been tested such as a centrifuge, a hydrocyclone, membranes and a corrosion inhibitor. Observations and conclusions from the tests are presented.
System Analysis of Oilfield Development Problems in Environmentally Sensitive Areas
Authors: Surthuthev L. , Basnieva I.
Published: December 2007

The development of major oil fields requires considerable primary resources consumptions. Vast use of land, water and energy, negative technogenic impact influence considerably on natural environment in local and regional aspects. Implementation of improved oil recovery (IOR) methods demands additional use of energy, expensive oil displacement agents, skilled personnel, specialised equipment etc.

Multicriteria analysis of oil recovery processes by use of primary resources allows to estimate the complex efficiency and rate of natural environmental impact. To achive the solution of multipurpose problem of. rational resources consumption in course of oil fields development procedure of optimization and compromise programming is carried out. The significance of used natural resources in different geographical regions is determined by environment protection expert analysis.

Natural environment systems in such regions as the North of the West Suberia and the Kaspean lowland are very sensitive to the processes of oil and gas fields development. The permafrost conditions and easy spoiled land fertile cover, the danger of earth subsidence and possible technogenic seismicity demand thorouth analysis of oil recovery projects applicability and their environmental safety.

Complex efficiency assessment and multicriterion optimization of primary resources consumption have been done for the design versions of development of large oil fields Russkoe and Tengiz. Analysis of verious IOR methods on the basis of primary and energy resources consumption allows a better choice of natural environment saving technology and shows the direction and necessity of their further improvement. Study of possible technogenic effects caused by oil field development is of prime importence for timely prevention from negative consequences for nature in the region.
Improved Reservoir Management by Integrated Study: Cormorant Field, Block 1
Authors: Grant I. , Marshall J. D. , Dietvorst P. , Hordijk J.
Published: December 2007

The Cormorant field, in the East Shetland Basin of the Northern North Sea, consists of four oil accumulations in the productive Brent Group. Block I, the central structure, is a 15 km long, north-south trending and westerly tilted fault block with crestal erosion.

To evaluate future development options and to provide a realistic forecasting and monitoring tool, a multi-disciplinary Petroleum Engineering study was carried out. A complete geological and petrophysical review was undertaken as an integral part of the study. This included a reservoir geological description of the main reservoir units, an analysis of the sealing capacity of the internal faults, and permeability prediction using multi-linear regression. The results of the review formed the basis for the detailed Block I 3D reservoir simulation model.

History matching identified the key reservoir parameters responsible for the observed pressure and water cut trends. These were the sealing capacities of the faults, the transmissibility between reservoir units, and the differing sedimentary fades (channel, barrier, interchannel, mouthbar, lagoonal beach) in the Etive and Lower Ness reservoir units. The facies variations were found to exercise considerable control on permeability trends and fluid displacement efficiency. Their proper description proved fundamental.

The model has been used to evaluate alternative development options. These have led to the formulation of a new development plan that should increase ultimate recovery in the order of 10% (20 MMstb) [3.2 × 106 m3].
Use of Borehole Gravimetry for Reservoir Characterisation and Fluid Saturation Monitoring
Authors: Popta J. V. , Heywood J. M. T. , Adams S. J. , Bostock D. R.
Published: December 2007

This paper describes the results of a field application of borehole gravimetry to measure secondary gas saturations in a fractured limestone reservoir. Owing to its deep-reading capability and insensitivity to near-wellbore effects, the borehole gravimeter succeeded where conventional cased-hole logging methods had failed. Borehole-fluid pressure data, recorded together with the gravity data, proved useful in ensuring that the density data had the necessary high accuracy. This paper additionally presents modelling results that indicate the potential usefulness of time-lapse borehole gravity data for monitoring floodfronts remote from a borehole. This application would benefit from the development of a sensor with a very reliable absolute calibration and low drift.
Modelling the Performance of High-Pressure High-Temperature Wells
Authors: Baker A. C. , Price M.
Published: December 2007

SYNOPSIS

Drilling into high pressure high temperature reservoirs gives rise to additional hazards which are not present in more conventional reservoirs. High surface temperatures and pressures may result when reservoir fluids are brought to surface either during production testing or in a well pressure control operation. Accurate estimation of pressure and temperature profiles is required during the well planning stage to ensure that downhole and surface equipment is specified which can meet these criteria. Critical temperature-sensitive equipment items include the elastomeric seals used in BOP's, valves, wellheads and flexible hoses.

There is also a requirement for the calculation of temperatures downstream of the choke when circulating out a gas-kick under controlled conditions, in order to check for possible cryogenic temperatures and hydrate formation downstream of the choke valve.

While computer simulation models are of great assistance in predicting surface pressures and temperatures, maximum use should also be made of available reservoir fluid data and historical production test data from similar wells in order to test and validate the models. Such an exercise has the dual benefit of highlighting any shortcomings within the models and increasing confidence in further predictive modelling.
Safety for the 90's: A Drilling Contractor's Perspective
Authors: Tait S. , Mumford G.
Published: December 2007

In the aftermath of several highly publicised events in the North Sea a drilling contractor has taken a fresh look at their safety programme. It was decided to concentrate on making it an employee oriented programme with the key element being commitment from the rig personnel. At the end of 1989 their lost time injury frequency rate had improved by over 30% in spite of increased activity and high turnover in all sectors of North Sea industry and a corresponding decrease in the level of experienced personnel in many positions. This paper describes the steps taken in this programme, their results and how they will be followed up in the 1990's.
Economics of Gas Conversion Projects in the North Sea and Barents Sea
Authors: Antia D. D. J. , Seddon D.
Published: December 2007

Different processes, costings and economics for the development of marginal and giant offshore gas fields, as synthetic fuel and commodity chemical producers are evaluated. The processes have become economic as a result of improved process design, modularised construction techniques, targeted high value added finished products (e.g: methanol, unleaded gasoline, waxes, etc.), new catalyst technology, and process technology.
Practical Application of Computer Technology to Petroleum and Gas Operations
Authors: Gaffney P.D.
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.

Detailed reservoir calculations, large-scale pipeline design and many refining operations now are carried out with the use of computer techniques. However, routine handling of small projects such as the calculation of oil and gas reserves, the evaluation of pressure buildup data for production and reservoir applications, etc., continues to be done to a large extent by manual techniques.

This paper discusses the considerable potential for the operations engineer in using potential for the operations engineer in using both the results of simple data processing and the new small scientific computer. It is concluded that valuable improvements in the use of technical manpower would result from a greater understanding and application of these modern techniques.

Introduction

The application of computers and data processing to the solution of technical processing to the solution of technical problems for the petroleum industry has seen great problems for the petroleum industry has seen great progress in recent years. However, in many progress in recent years. However, in many respects, this application has been limited to the more mathematically inclined and to those engineering problems involving detailed repetitive solutions such as process and reservoir engineering calculations. The application of these techniques to the day-today engineering problems besetting the individual field problems besetting the individual field engineer has not yet been universally accepted. This paper examines these applications in the light of more recent computer and data processing developments, and illustrates the processing developments, and illustrates the advantages of applying such techniques to routine daily problems.

DEFINITIONS

"Data processing" in this context refers to all machine processing that requires simple multiplication, division, addition and subtraction and the carrying of totals. These tasks need relatively uncomplicated sorting machines, printers, card readers, punches and a small printers, card readers, punches and a small arithmetic unit. A "computer", on the other hand, refers here to a processing machine that has considerable memory [storage] capacity and can perform calculations much faster than the simple data processing machine. However, while in many cases data processing problems are carried out on computers because of their greater capacity, it is rarely possible to reverse this and solve even simple engineering problems on data processing equipment. problems on data processing equipment.
Economics of U.K. Field Abandonment
Authors: Antia D. D. J.
Published: December 2007

The financial risks associated with UK field abandonment are identified. Different risk minimisation and value enhancement strategies for the abandonment of UK fields are discussed. They include facility reuse, abandonment deferral, insurance, turnkey production leases, sale and leaseback, divestment, acreage-production swaps, and crossfield offsets. The adoption of an appropriate abandonment strategy can significantly reduce the after-tax cost of abandonment.
Comparison of Deterministic and Probabilistic Simulation Models of Channel Sands in the Statfjord Reservoir, Brent Field
Authors: Keijzer J. H. , Kortekaas T. F. M.
Published: December 2007

The Brent Field has an estimated STOIIP of 3,440 MMstb and a GIIP of 6.9 Tscf. The field is operated by Shell on behalf of a Shell – Esso joint venture. It consists of two separate reservoirs, the Brent and Statfjord reservoir. Both reservoirs contain light oil, overlain by condensate rich primary gas caps. Definition of an optimal long-term development plan for the Brent Field required the construction and application of the so-called Brent Full Field Simulation Model. A key issue in the construction of reservoir simulation models of the field is the description of the reservoir geology. The description of channel dominated sands in the Statfjord reservoir was anticipated to pose major difficulties in the history matching process. Therefore, the merits of using more detailed geological models, in particular probabilistic models, were investigated. Well data were used to generate three probabilistic models of the geological most complex middle reservoir units of a part of the Statfjord reservoir. To incorporate vertical crossflow, these models were embedded between the deterministically modelled over- and underlying reservoir units. Extensive software was developed to translate the extremely detailed models (>150,000 blocks) into coarser simulation models. To allow for a valid comparison between the probabilistic approach and the conventional deterministic approach, a completely conventional model with identical grid definition was built for the same part of the reservoir.

Simulation of the displacement characteristics revealed that the incorporation of the more detailed geology led to a substantially improved description of the historical well performances. The implicit definition of shales in the probabilistic models proved to be an important characteristic: the production performance in the over- and underlying non-probabiiistically modelled layers was significantly affected by the inclusion of the detailed geology in the probabilistically modelled layers.

In view of the promising results, the use of more detailed geological models in future generations of the Brent Full Field Simulation Model is being reviewed.
Evaluation of Capacity and Gas Yield of Low-Porous and Low-Permeable Reservoirs
Authors: Teumer P. , Voight H. D.
Published: December 2007

Significant gas reserves are accumulated in "tight" gas sands in the German Democratic Republic (Eastern Germany). This potential mainly occurs in layers that form the overlying and underlaying sections of higher permeable payzones. In order to etablish the development of the resevoir in such way, that maximal gas yield and production are achieved the following extensive investigations were carried out:

– degasification and pore size measurements, – porosity mesurements in dependence confining pressure, – special drillstem tests (DST), – pressure buildup behaviour in layered reservoirs, – estimation of the gas recovery factor, – material balance behaviour in layered reservoirs.

The objective of this paper is to report the results of this investigations.
Planning, Implementation, and Analysis of the First Troll Horizontal Well Test
Authors: Hovland S. , Jones C. , Whittle T.
Published: December 2007

Details are given of the design, implementation and analysis of the initial well testing and production logging of a horizontal well recently drilled in the North Sea. Test rates of 2000 Sm3/d of oil were measured with a drawdown of 0.26 bar producing through a wire wrapped pre-packed screen. The production log verified the majority of the well to be producing and, with the aid of a type curve presented here, the pressure build-up analysis yielded the effective vertical permeability of the reservoir.

The test confirmed the suitability of the well for long-term testing during which stable liquid rates of 5000 Sm3/d have been produced.