bluuebunny/crossref_metadata_2025 huggingface dataset:
Liquid Addition to Steam for Enhancing Recovery (LASER) of Bitumen with CSS: Evolution of Technology from Research Concept to a Field Pilot at Cold Lake
Authors: Léauté Roland P.
Published: December 2007

This paper describes the process of injecting a liquid (C5+) hydrocarbon as a steam additive in a CSS mode of operations. The process has been termed LASER, for "Liquid Addition to Steam for Enhancing Recovery".

The process concept was first tested in a 3D physical model apparatus using Cold Lake bitumen. A sustained uplift in bitumen production was observed in later CSS cycles when compared to other tests conducted without liquid addition. Based on numerical simulations, these effects can be attributed to additional viscosity reduction of heated bitumen when contacted with solvent. For bitumen-diluent mixtures, Shuh’s method of viscosity prediction of bitumen with liquid hydrocarbons is adequate to make realistic viscosity predictions based on actual measurements. Field-scale simulations were used to support LASER performance trends from the physical model and establish the optimal timing for applying the technology in the field.

The key recovery performance indicators for LASER technology are (1) bitumen uplift over continued CSS performance and (2) fractional recovery of the injected diluent. A field pilot has been designed based on expectations of (1) an improvement of 33% in the cycle Oil-Steam Ratio (OSR) and (2) diluent recovery of 66% using 6% v/v of diluent injection with steam. The pilot location was chosen based on various factors, including improved characterization of historical performance within and around the pilot location. This was achieved by developing a novel multivariate analysis technique to correlate current OSR field performance and reduce associated background noise.

An extensive monitoring program has been developed for the pilot. This program is critical for developing a reliable characterization of the diluent recovery. Diluent injection began in April 2002, and the pilot is expected to last approximately 2 years, corresponding to the average length of CSS cycle 7 at Cold Lake.
Injection Pressures for Geomechanical Enhancement of Recovery Processes in the Athabasca Oil Sands
Authors: Collins Patrick M.
Published: December 2007

This paper describes a geomechanical approach to the determination of injection pressures that will result in formation shearing within the Athabasca oil sands. The enhancement of in situ permeabilities, resulting from shearing, is a beneficial phenomenon and often an essential prerequisite of many successful in situ recovery processes.

This geomechanical analysis is based upon the general geological setting in the Athabasca oil sands, observations made from field data, published laboratory data, and geomechanical principles. The first objective was to estimate the existing stress state in the rock. This determination was based on elastic theory and tectonics, and fitted to field measurements of the minimum in situ stress from minifrac tests in the Athabasca oil sands. The methodology also calculates the maximum horizontal stress, a parameter that is extremely difficult to measure, yet is an important parameter for most stress analyses. The resultant stress anisotropy creates the potential for formation shearing; a potential that is unleashed once the effective stresses are sufficiently reduced with high injection pressures.

Lastly, the amounts by which injection pressures must be increased for shear failure are provided, assuming typical values of formation strength.

The analysis begins with a determination of the minimum in situ stress, as a function of depth. This is the fracture closure pressure that is a useful parameter in determining fracture treatment pressures, fracture containment, and fracture orientation. The associated tectonic strain is used to calculate the maximum horizontal stress. Using the maximum and minimum stresses, the injection pressure at which extensive shearing will occur is calculated. This is the geomechanical optimum operating pressure. While other considerations may favour a lower operating pressure, recovery processes that rely upon high in situ permeabilities may not be viable at lower injection pressures.

The methodology presented is applicable to other regions.
Fracture Evaluation With Pressure Transient Testing In Low-Permeability Gas Reservoirs. Part I: Theoretical Background
Authors: Lee W.J. , Holditch S.A.
Published: December 2007

Introduction

The purpose of this paper is to summarize the theoretical background of methods which we have attempted to use to determine formation permeability, fracture length, and fracture conductivity in low-permeability, hydraulically fractured gas reservoirs. This summary is intended to emphasize the major strengths and weaknesses of the methods studied. These characteristics have not always been emphasized in the original literature and have, in some cases, remained obscure to the practicing engineer. This pape is a companion paper to SPE 79301, in which our experience in application of these techniques to problems arising in practice is discussed. Test analysis methods discussed in the paper include (1) a method applicable only after a 'pseudo-radial' flow pattern is developed in the reservoir, (2) a method applicable when linear flow dominates in the reservoir, (3) published type curves, with emphasis on those which include finite-conductivity fractures, (4) a modification of linear-flow techniques useful for finite-conductivity fractures, and (5) use of finite-difference reservoir simulators in a history-matching mode.

Pseudo-Radial Flow

Russell and Truitt2 pioneered application of methods based on the assumption of 'pseudo-radial flow' in a fractured reservoir for determination of formation permeability and fracture length. A working definition of pseudo-radial flow is that sufficient time has elapsed in a buildup or drawdown test so that bottom-hole pressure varies linearly with flow time (drawdown) or the Horner time group, (tp+Î"t)/Î"t (buildup), as expected for radial flow in an unfractured reservoir.

In an infinite-acting (unbounded) reservoir, the analysis technique is based on the use of skin factor, s, which can be calculated fromEquation 1*

and the observation tat, for infinitely-conductive vertical fractures,Equation 2

Eqs. (1) and (2) can be combined to avoid the need for the intermediate step of calculating skin factor, s,Equation 3

In principle, we can plot buildup test data on a conventional Horner graph, determine the slope, m, and thus estimate formation permeability (k=162.6 qgBgiÎ¼i/mh) and determine fracture half-length, Lf, from Eq. (3). (See Figure 1.) In practice, there are three serious problems with this method:The time required to reach the required straight line where the slope is related to formation permeability can be impractically long (months or years) in low permeability gas reservoirs with long fractures, as demonstrated by Gringarten, et al.4 and Cinco5 et al.;Implicit in the method is the assumption of infinite fracture conductivity, which is not always valid6; and,By the time the pressure transient has moved beyond the region of the reservoir influenced by the fracture, effects of the reservoir boundary may have already become important, preventing development of the proper slope, m.
Geological Characteristics And Engineering Capabilities Of Wells 31-13 And 498-4-1
Authors: Timmerman E.H. , Collins T. , Ishteiwy A.A. , Chancellor R.E.
Published: December 2007

Two wells in the Northern Piceance Basin were variably stimulated in correlative Mesaverde rocks. The well which encountered the rock sequence at greater depth in the presence of more intensive natural fracturing had better productive characteristics and better before and productive characteristics and better before and after flow capacity. Geology, flow data and buildup data are in agreement. The data also indicate that the overall net benefit of massive fracture is about the same as obtainable from a moderate size fracture job. Methods used to analyze the buildup tests are illustrated in the Appendix section.

Selective fracturing of available individual gas zones using moderate sized operations per zone is useful. Hopefully, a technique can be developed which, in the field, will attain benefits indicated by theory to be obtainable from massive fractures in Western Tight Gas pays. Frac fluids can be displaced today, but results are less than desired.

Introduction

Two industry-government projects to improve production from tight gas sands of the Mesaverde production from tight gas sands of the Mesaverde Formation, Northern Piceance Basin, have progressed sufficiently to yield data which progressed sufficiently to yield data which (supplemented by earlier but less thoroughly documented drilling and completion efforts in the general area) is of correlative interest. A total of nine fracture stimulation treatments have been performed in the two wells shown on Figure 1. Well No. 498-4-1 (498) is about 11 miles southwest of Well No. F31-13G (31-13). Structurally, Well No.498 is approximately 3,000 feet higher than Well No. 31-13. Well No. 498 is located on regional (41) while Well No. 31-13 is near the crest of the Piceance Creek Dome. The Dome experienced strong structural movements following deposition of Mesaverde sediments.

P. 271
Modeling Sand Production and Erosion Growth under Combined Axial and Radial Flow
Authors: Wan Richard G. , Wang Jin
Published: December 2007

The paper investigates the phenomenon of sand production in both axial and radial flow conditions using a coupled particle erosion-fluid transport-stress model that has been developed recently by the authors. We first examine sand production and wormhole growth in a sand pack as heavy oil is being drawn from it through a small orifice. Numerical results are in close agreement with experimental data available for the sand pack experiment. In particular, the computed porosity field and its temporal evolution during wormhole propagation match very well with available CT scan images of the sand pack. Then, we model a sand production hollow cylinder test in which sand is being produced under combined axial and radial flow of light oil in a sandstone specimen. Aspects such as sand flux and porosity evolutions, as well as erosion growth around the inner wall of the cylinder are investigated using the numerical model.
Scale Inhibition Problems Associated With North Sea Oil Production
Authors: Boyle M.J. , Mitchell R.W.
Published: December 2007

Suitable chemical treatment of North Sea oil and gas production plays a small but vital role in determining the production plays a small but vital role in determining the success of the project. During the initial period of production from a new oilfield, the chemical treatment requirements are generally minimal. This situation changes dramatically as the field life progresses and water production commences. At that time a variety of chemicals will probably be required including demulsifiers, corrosion inhibitors. effluent treatment compounds and scale inhibitors. Whilst for many of these products there are well defined test methods and selection techniques available, this is a particular problem with scale inhibitors. In the majority of particular problem with scale inhibitors. In the majority of cases it is very difficult to simulate the scaling situation present in the field by laboratory methods. present in the field by laboratory methods. The paper reviews some scale inhibitor selection techniques used in the past and describes a novel simulation test to monitor inhibition and flow pattern influence around an injection or production well bore. This method has been used to rank the efficiency of commercially available scale inhibitors for both the Forties injection and production systems and will be discussed in terms of the practical problems involved. problems involved

Introduction

Problems arising from the production of scale are commonplace in oilfields. The precipitation mechanism is often complex and may be due to a variety of effects including changes in system conditions (e.g. pH, pressure. temperature etc.), reservoir conditions or incompatibility between injected water and formation water. The present paper discusses carbonate and sulphate scale formation in the Forties Field and some of the laboratory inhibitor selection techniques used in the selection of suitable scale inhibitors for field use both in the Forties injection and production systems. In particular a novel test method is described which is being used in the laboratory to monitor inhibitor and flow pattern influence on formation scaling.
Field Studies: A Progress Report On The Contribution Of Logging
Authors: Boutemy Y. , Clavier C. , Simond R.F.
Published: December 2007

Introduction

In recent years a new method has evolved which allows the merging of wireline surveys, core and other sample data, and geological and geophysical information to estimate reservoir properties. The method makes extensive use of 'Kriging' and multidimensional histograms. The name 'Field Study' has been retained to depict very generally the method. A field study consists, therefore, of a unified interpretation of wireline measurements, core and sample data, done on a fieldwide basis. This fundamental work is followed by an estimation of the spatial distribution of various key parameters over selected reservoirs of a field. Reservoir geometry, thickness, distribution of porosity, permeability and fluid saturation are typical parameters to permeability and fluid saturation are typical parameters to be estimated together with their integration and required combinations to obtain total pore volume, hydrocarbon in place, permeability-height, etc. All these factors are place, permeability-height, etc. All these factors are crucial to the economics of field development and productivity. productivity. At present, a large part of the input parameters for such a study consists of open-hole wireline measurements and/or data subsequently obtained from these by computer processing. processing.
"Real Gas Pseudo-Time" - A New Function For Pressure Buildup Analysis Of MHF Gas Wells
Authors: Agarwal Ram G.
Published: December 2007

A new time function has been defined which considers variations of gas viscosity and compressibility as a function of pressure, which in turn is a function of time. This function appears to be similar to the real gas pseudo-pressure, m(p) of Al-Hussainy et al., which takes into account the variations of gas viscosity and z-factor as a function of pressure. However, this is an approximate function as opposed to m(p). This time function will be referred to in this paper as the real gas pseudo-time, t a(p). This function has aided in pseudo-time, t a(p). This function has aided in post-treatment-pressure buildup analysis of post-treatment-pressure buildup analysis of fractured (including MHF) gas wells by type curve analysis. Results of computer simulated pressure buildup analysis indicate that the use of t a(p) provides satisfactory values of computed fracture provides satisfactory values of computed fracture lengths in fractured gas wells.

In this paper the real gas pseudo-time is described and its application is demonstrated by means of example problems. Although the discussion in this paper is limited to pressure buildup analysis of vertically fractured gas wells, the utility of this function is not meant to be restricted to such wells only.

Introduction

In recent years, type curve analysis methods' have become well known in the petroleum industry for analyzing both pressure drawdown and buildup data in oil and gas wells. These methods are meant to be used in conjunction with the conventional methods whenever possible. Exceptions appear to be MHF gas wells with finite flow capacity fractures where conventional methods are not readily applicable and, at least to date, only type curve methods appear practical to determine fracture length and fracture flow practical to determine fracture length and fracture flow capacity. Although the majority of published type curves, including those for MHF wells, are based on the pressure drawdown solutions for liquid systems, they can be used in an approximate fashion to analyze pressure data from real gas wells. The first requirement is that the dimensionless pressure and time variables are appropriately defined for gas wells. For example, to use the liquid system type curves for an MET gas well, dimensionless variables are defined as follows:

Dimensionless pressure,

(1)

(In SI units, the numerical constant is 128 × 10(-3))

Dimensionless pressure, for a gas well, may also be expressed in terms of Delta (p) or Delta p.

Dimensionless time,

(2)

(In SI units, the numerical constant is 3.6 × 10(-9))

The definition of dimensionless fracture capacity remains the same.

(3)

Note that in Eq. (1), the real gas pseudo-pressure, m(p) of Al-Hussainy et al. has been used to take into account the variations of gas viscosity and z-factor as a function of pressure. In Eq. (2), viscosity-compressibility (mu c t)i is shown to be evaluated at the initial reservoir pressure. pressure.
An Improved Nuclear Magnetism Logging System And Its Application To Formation Evaluation
Authors: Herrick R.C. , Couturie S.H. , Best D.L.
Published: December 2007

A new version of the Nuclear Magnetism Logging tool (NML) has been developed and will be available for limited commercial use in the near future. The tool measures the earth's field proton free induction decay of formation fluids. Since this tool operates exclusively with the CSU well-site computer system, it is capable of real-time computation and presentation of the free fluid index (FFI) and the spin-lattice relaxation time (T1). Other new features include a centralized coil sonde and improved electronics for higher signal-to-noise ratio and greater reliability. Engineering prototypes have been extensively field tested and have proven to be dependable in a logging environment. Logs correlate well with other porosity measurements from core data and sonic, nuclear, and electromagnetic propagation well logging tools. Data from NML logs can be applied to the determination of irreducible water saturation, porosity in unusual lithologies, residual oil saturation, and porosity in unusual lithologies, residual oil saturation, and to the estimation of permeability.
Safety Economics and Rig Contracts
Authors: Osmundsen Petter , Toft Anders , Dragvik Kjell Agnar , Heldal Tor , Larsen Inge Arild
Published: December 2007

The main topic of this article is how financial incentives can impact focus on safety. The case used is the relationship between the operator of a petroleum license and a drilling contractor. Focus is placed on how an operator can influence the actions of a drilling contractor with the aid of financial incentives both in connection with hiring in rigs and contract design. Furthermore, the article examines how these incentives can influence the contractor's focus on safety.

The report is based in part on contract and incentive theory – see e.g. Laffont and Tirole (1989) and Salanié (1999) – and in part on empirical data. The empirical basis consists of various drilling contracts utilized on the Norwegian and British shelves, as well as meetings and informal conversations with representatives of oil companies, rig companies and safety administrators.

There are some general development trends in the offshore sector; such as outsourcing, focus on financial indicators and increased focus on incentive-based compensation schemes, that have led to an increased emphasis on incentive clauses in contracts, thus making this topic even more relevant. The growing degree of outsourcing has meant that transactions previously conducted within the same organization are now governed by means of contracts between independent companies. We also see an increasing degree of management by objectives in the companies, including increased emphasis on financial indicators. One of the effects of this change appears to be a growing emphasis on financial performance on a quarterly and annual basis. This management by objectives is followed up internally within the companies and in contracts between independent companies, in part through the formulation of incentive agreements.
Treatment of Waste Water: A Reed Bed-Environmental Case History
Authors: Guirguis Maurice
Published: December 2007

A reed bed or constructed wetland has proven to be an effective, sustainable, reliable, and economical treatment method for sewage or industrial waste. The reed-bed treatment systems in desert area 103, Libya, are self-contained, artificially engineered wetland ecosystems. They are designed to optimize the microbiological, chemical, and physical processes naturally occurring in the wetland. This paper describes the construction of the treatment plant, its wastewater treatment capacity, and the positive impact it has had on the environment and the local community.

The reed-bed wastewater treatment plant in desert area 103 is the first wastewater treatment facility in the Libyan desert oil fields. It can treat up to 350 m3 of wastewater effluent per day using automatic submersible pumps. The reed bed is lined with plastic sheets underneath the gravel to prevent effluent from seeping underground. Wastewater is discharged to the reed bed for treatment after primary tank screening and settling. Wastewater enters the reed bed by gravity via clean stone for biological treatment on the stone surface.

The common reed Phragmites australis is indigenous to the Libyan desert 103 area. It has the ability to transfer atmospheric oxygen from its leaves down through its stem, porous septa, and rhizomes, and out into the rhizosphere (root system). As a result, a very high population of microorganisms exists in the rhizosphere, in zones of aerobic, anoxic, and anaerobic conditions.

The plant is currently treating between 60 and 80 m3 of wastewater per day. The reed-bed wastewater treatment project improved the scenery and odor of the wastewater area, protected the potable water well in the middle of the camp and the water table, and reduced the ecological impact on the endangered wildlife in the area. This project has shown that treating wastewater in remote locations is feasible.
Environmental Aspects of the Use and Disposal of Non Aqueous Drilling Fluids Associated with Offshore Oil & Gas Operations
Authors: Melton H. R. , Smith J. P. , Mairs H. L. , Bernier R. F. , Garland E. , Glickman A. H. , Jones F. V. , Ray J. P. , Thomas D. , Campbell J. A.
Published: December 2007

High-performance non-aqueous drilling fluids (NADFs) are required to meet the challenging technical requirements of many offshore wells. Significant advances have led to the development of advanced NADFs, such as paraffins, olefins and esters, that are less toxic and more biodegradable than early generation diesel and mineral oil base fluids. Advanced NADFs provide the necessary drilling performance while ensuring environmentally-sound operations.

Three options exist to manage waste from NADF-coated drill cuttings: marine discharge, downhole injection, and hauling to shore for land disposal. All options have advantages and disadvantages with regard to total life cycle environmental impact, safety, cost, and operational performance. Marine discharge of cuttings associated with advanced NADFs, however, is the option with the highest safety and operational flexibility. Further, the improved environmental performance of advanced NADFs broadens the acceptability of marine discharge.

Field monitoring studies at multiple offshore drilling sites reveal a relatively consistent picture of the fate and effects of discharging drill cuttings associated with NADFs. The degree of impact is a function of local environmental conditions (water depth, currents, temperature), the amount of material discharged, and the type of drilling fluid used. More significant temporal and spatial effects were observed at sites that used early generation drilling fluids. Wells drilled with advanced NADFs resulted in smaller zones of seafloor impact and more rapid recovery of the benthic communities.

This paper, based on the work performed by a task force of the International association of Oil and Gas Producers (OGP)1, summarizes our knowledge base of the environmental-effects related to the discharge of NADF-coated drill cuttings. In addition, it describes tools and techniques for assessing environmental effects including laboratory methods to determine drilling fluid toxicity, biodegradability, and bioaccumulation potential and numerical models to predict the seafloor distribution of cuttings.

The paper is intended to aid regulatory development and project environmental assessments by providing information to help balance environmental, operational, and cost considerations when choosing waste-management options for NADF drilling.
Tackling Road Safety In a Global Upstream Business: An Integrated and Long Term Approach
Authors: Malone Charles
Published: December 2007

In a global upstream company effectively managed road transport is a vital component to the success of an operation. If it is not managed effectively the consequences when things go wrong are severe and can ultimately lead to loss of human life, which is intolerable. This paper explains the integrated approach that Shell Exploration and Production is currently embarking on to tackle road safety globally for the long term.
The Future of the Petroleum Industry in California and Louisiana
Authors: Cook P.G.
Published: December 2007

The demand for crude oil in California and Louisiana, respectively, by 1967, is anticipated to approximate 700 million bbl and 600 million bbl annually. Natural gas consumption in California is anticipated to rise to 3.0 billion Mcf annually which will require the importing of some 2.4 billion Mcf to supplement production. The total consumption of natural gas in Louisiana is anticipated to increase to 1.6 billion Mcf and leave about 2.9 to 4.5 billion Mcf for exportation.

The anticipated drilling activity in California is anticipated to increase to 2,440 walls annually and then decline to 2,260 wells annually by 1967. In Louisiana, the number of wells drilled annually may reach 7,000. The total footage drilled annually and the average well depth will increase in both states.

The anticipated California total capacity to produce will decline to 28 B/D/well by 1958, while in Louisiana the anticipated capacity to produce will be around 53 B/D/well. Primary production of crude oil will decline in California to an anticipated 310 million bbl annually and in Louisiana production will increase to 660 million bbl. It is thought that natural gas production will decline to 535 million Mcf in California and in Louisiana it will increase to a value of 4.5 billion Mcf.

The production - discovery ratio for California is anticipated to climb to 5 to 1, and over the projected time 1.5 billion bbl of new oil will be discovered, yet the reserves are anticipated to decline to about 2.2 billion bbl. The natural gas reserves are anticipated to decline to about 3.62 billion Mcf. Offshore crude oil and natural gas reserves are estimated at a maximum of 4.0 billion and 9 to 10 billion Mcf. Present Louisiana onshore crude oil reserves are indicated to be 7.1 billion bbl. Offshore reserves are estimated at 12 billion bbl of crude oil and about 100 billion Mcf of natural gas.

A summation of various crude oil production curves indicate that California peak production may not occur until 1965 and could well attain a value of 380 million bbl annually. At the anticipated rate, peak production in Louisiana may occur in 1975 with a possible value of 730 million bbl annually.
3D Geological Modeling of a Carbonate Reservoir, Utilizing Open-Hole Log Response – Porosity & Permeability – Lithofacies Relationship
Authors: Akatsuka K.
Published: December 2007

A lithofacies based reservoir characterization study was conducted for a Lower Cretaceous carbonate reservoir in order to build a numerical 3-dimensional geological model including permeability prediction and rock typing for reservoir flow simulation.

This paper describes a procedure for constructing a lithofacies based geological model for reservoir flow simulation. This is the first time a lithofacies based reservoir characterization has been applied to the target reservoir. We believe this model is a reasonable representation of the reservoir as it gave a good match between predicted permeability and well test permeability.

Nine lithofacies were identified from detailed slabbed core observations and lithofacies of non-cored wells were predicted from the cross plots between DT, RHOB, PHIE and MSFL of each lithofacies.

The relationship between lithofacies and open-hole log response was also effective in estimating the spatial distribution of each lithofacies. A lithofacies trend map, which shows the lateral variation of lithofacies, was produced by applying this relationship to maps of vertically averaged log response. A lithofacies distribution map was prepared by incorporating a geological interpretation of thickness and porosity variations into the trend map.

Horizontal permeability was predicted from simple core porosity-permeability regressions for each lithofacies using log porosity as the input. Using the lithofacies distribution map and the relationship between porosity and permeability of each lithofacies, the lateral variation of horizontal permeability was predicted without direct interpolation or extrapolation of permeability data between wells. The general trend of this modeled permeability was similar to the permeability derived from production tests. However, the absolute value of modeled permeability was lower than the well test permeability across the reservoir. This phenomenon might be due to the existence of high permeability streaks which were not cored.

Investigation of the relationship between lithofacies and petrophysical data, such as special core analysis, was carried out based on pore throat size distribution curves derived from capillary pressure data. As a result, four rock types were identified in the reservoir.
Predictive Modelling of Naturally Fractured Reservoirs Using Geomechanics and Flow Simulation
Authors: Bourne Stephen J. , Brauckmann Franz , Rijkels Lex , Stephenson Ben J. , Weber Alex , Willemse Emanuel J. M.
Published: December 2007

To optimise recovery in naturally fractured reservoirs, the field-scale distribution of fracture properties must be understood and quantified. We present a semi-deterministic method to systematically predict the spatial distribution of natural fractures and their effect on flow simulations. This approach enables the calculation of field-scale fracture models. These are calibrated by geological, well test and field production data to constrain the distributions of fractures within the inter-well space.

First, we calculate the stress distribution at the time of fracturing using the present-day structural reservoir geometry. This calculation is based on geomechanical models of rock deformation such as elastic faulting. Second, the calculated stress field is used to govern the simulated growth of fracture networks. Finally, the fractures are upscaled dynamically by simulating flow through the discrete fracture network per grid block, enabling field-scale multi-phase reservoir simulation. Uncertainties associated with these predictions are considerably reduced by constraining and validating the models with seismic, borehole, well test and production data.

This approach is able to predict physically and geologically realistic fracture networks. Its successful application to outcrops and reservoirs demonstrates there is a high degree of predictability in the properties of natural fracture networks. Several examples show the success of the method in single- and multi-phase fields. In cases of limited data – where stochastic models typically fail – this method remains robust.
Full Field Reservoir Simulation Study of an Oil Rim in a Field Offshore Abu Dhabi (UAE)
Authors: Decroux Bruno , El Emam Medhat , Nassar Omar , Kadada Talal , Karakhanian Hagop
Published: December 2007

This paper presents a case study drawn from a full field simulation study on an oil rim in a field offshore Abu Dhabi.

Initially the reservoir contained a large gas cap underlain by a thin saturated oil rim. The gas production from the gas cap started in 1976. In 1989, about 22% of the gas from the gas cap had been produced. The reservoir pressure had dropped by more than 1100 psi. Then gas injection from a deeper reservoir into the gas cap started and the reservoir was slowly repressurised. However, a moderately active aquifer encroached and flooded part of the oil rim. The oil was pushed up dip.

The main objective of the study was to propose a full field development scheme for the oil rim. Meanwhile, the opportunity was taken to optimise the condensate recovery.

A multidisciplinary reservoir characterisation study was carried out on the formation. Based on this study, seven rock types were defined and a reservoir-layering scheme was developed. A full field compositional simulation model was built and history matched. The history match included the match of six oil producers, which experienced water and/or free gas production. The Gas Cap CGR history was also successfully matched.

Finally, the history-matched model was used for recommending a development scenario. Few oil producer concepts were tested. Several development scenarios were compared. One of the scenarios was assuming gas cap depletion after year 2005 while the other scenarios were assuming partial or full recycling at different rates.
Optimization of Process Parameters for Glycol Unit to Mitigate the Emission of BTEX/VOCs
Authors: Braek A. M. , Almehaideb R. A. , Darwish N. , Hughes R.
Published: December 2007

Recent developments in environmental regulations have made emissions of the aromatic compounds Benzene, Toluene, Ethyl-Benzene, and Xylene isomers (BTEX) and other Volatile Organic Compounds (VOCs) from glycol units a major concern for the natural gas industry. Hence, quantifying the absorption levels has become more important in recent years due to increased restrictions on BTEX/VOC Emissions from glycol dehydration units.

This problem is one, which requires careful attention in the design phase, and also the environmental considerations as mentioned above are increasingly driving the selection and operation of process alternatives to reduce the BTEX/VOCs emissions in the atmosphere.

In this paper, we will focus the study on one of the glycol dehydration unit for one of the onshore petroleum fields at Abu Dhabi managed by ADCO. Firstly, we quantify the BTEX/VOCs emission levels vented out to atmosphere, along with a description of the sampling technique used. Secondly, we optimize the process parameters around all major equipments in the glycol unit, i.e. absorber, flash tank, and regenerator. The optimization study will start by building a process simulation model which is based on actual design data given by the glycol unit vendor and verified by operational data.
Replacement of Cold & Cryogenic Insulation on a Live LNG Plant
Authors: Clements G. D.
Published: December 2007

This paper is a review from inception through execution to the status today of an ongoing ADGAS project to replace cold and cryogenic insulation without shutting down, i.e. during operational (live) conditions. It comprises historical background and the technical, operational, safety and environmental, contractual, and commercial aspects of what is thought to be the first large scale application in the Middle East of patented technology for replacing deteriorated cold and cryogenic insulation on live plant. It is a technology that has applications throughout the petrochemical industry wherever the difficult decision of whether to shut down for such repairs has to be made.
Vortex Meter Application for SCADA System Multiphase Flow Measurement
Authors: Hoadley S. F. , Al-Mutalri F.
Published: December 2007

With the introduction of the supervisory control and data acquisition (SCADA) systems, continuous field surveillance and control is made possible. Real time monitoring of producing well parameters i.e. flowing wellhead pressure, wellhead temperature, flowline pressure and flow rates is essential for maintaining production, monitoring well performance and managing field rates. Using remote sensors, the majority of these parameters are easily obtained with the exception of multiphase metering near the wellhead. Often the complexity of the equipment or the accuracy of the flow measurement present challenges for routine monitoring.

This paper outlines a simple process to effectively measure multiphase flow rates using low cost vortex or turbine type meters. Field results of 114 flow measurements before and after liquid/gas separation is presented to illustrate the accuracy level achieved. The results indicate fieldwide application of this technique is viable, in particular, when integrated with a SCADA system.
Monitoring and Controlling the Quality of Well Log Information
Authors: Al-Farisi Omar , Dajani Nasser , Boyd Douglas , Al-Felasi Ali , Al-Khatib Farouk
Published: December 2007

Reservoir management based on inaccurate or wrong information leads to confusion, frustration and poor decisions. Oil company subsurface specialists spend valuable time error checking, filtering and inspecting data extracted from company databases. End-users expect archived data to be correct. Primary objectives of the Petrophysics team in ADMA-OPCO are to deliver log data "fit for purpose"1 and "get it right the first time". To assist in achieving this, a system with measurable progress indicators was set up to plan, monitor, and quality check data and data flow. The foundation of this system is the CDLOGS (Control / Development Logging Sheet). The information provided by this sheet is followed up by OQSID (Operation, Quality, Safety and Interpretation Database), a database of quality indices. Analysis of its statistics highlights problems, corrective actions and allows quality to be continuously improved. These tools are the first steps in our development of a full quality assurance process.
Technology: Catalyst for Coalgas Growth
Authors: Jenkins C. D.
Published: December 2007

Over the past 20 years, coalgas has evolved from a mining nuisance to a robust industry that provides 7% of U.S. gas production. The key to this growth has been the development of new technologies to locate, quantify, and produce coalgas. Over the next 20 years, additional technological advances will be needed to identify new coalgas reservoirs and maximize recoveries from existing ones. Focus areas for these technologies include reservoir characterization, drilling and coring, wireline logging and well testing, completion and stimulation, production and water disposal, and improved recovery methods. This paper identifies some of the key technology needs in each of these areas, reviews recent innovations and showcases emerging technologies.
A Review of the Porter Field Unit Pressure Maintenance Project, Karnes County, Texas
Authors: Randle R.C. , Swaim R.J.
Published: December 2007

The Porter field unit is a 10 well project producing from a Pettus sand reservoir completely enclosed by faulting and sand pinch out. Primary reservoir performance was characterized by rapidly declining reservoir pressure and oil production, and increasing gas-oil ratios. A unit was formed in 1947. The program employed is injection of water down dip and return of produced gas to the gas cap. The project has been highly successful in arresting pressure and production declines and increasing ultimate recovery. Total oil recovery has already exceeded primary estimates by 29 per cent and productive capacity remains high. Movement of the water front has been uniform and water injection continued for four years before water production was obtained in the nearest producer 1,360 ft away.

The success of the project is attributable to the willingness of the operators to conduct a long term project with high water injection pressures, and low injectivity, in order to obtain increased ultimate recovery.

Introduction

The purpose of presenting the history and performance of the Porter field unit is to show how success was achieved in spite of several adverse conditions. The reservoir rock is shaley, containing bentonitic clay. Water available for injection is comparatively fresh. Electric logs and core data show that permeability is variable throughout the field. At the start of water injection, abnormally high pressures were necessary to inject even a limited volume of water. A fair degree of success was obtained, however, and fortunately the second well to be used for this purpose proved to be very much better. Injection of gas has not as yet increased oil production directly. It has served however, to reduce reservoir voidage and hence helped to maintain reservoir pressure.
Use of the Peng-Robinson Equation of State to Predict Hydrocarbon Phase Behavior and Miscibility for Fluid Displacement
Authors: Williams Craig A. , Zana Erdinc N. , Humphrys George E.
Published: December 2007

Recent advances in computer implemented equations of state have made predictions of phase behavior easier and more reliable. They have also led to a different approach in predicting first contact and generated miscibility in hydrocarbon systems. In this study, the Peng-Robinson Equation of State is used to provide equilibrium gas and liquid compositions at reservoir temperature and hypothetical reservoir pressures. In predicting miscibility, a system's two-phase envelope and associated tie lines are displayed as ternary diagrams. From these diagrams, a reservoir engineer can determine the minimum enrichment of intermediates (C2-C6) required for miscibility given reservoir pressure, reservoir fluid composition, and for a fixed reservoir temperature; or the minimum pressure for miscibility, given an injection gas and reservoir fluid composition. Experimental slim tube miscibility study results are compared to the method when available. We have successfully used this procedure to guide our laboratory reservoir evaluation programs, thereby saving experimental time and effort.
Applicability of Steamflooding for Carbonate Reservoirs
Authors: Nolan Jon B. , Ehrlich Robert , Crookston Reid B.
Published: December 2007

Steamflooding can be a technically effective recovery method for carbonate reservoirs within certain parameter ranges. The attractiveness of steamflooding relates to the fact that heat conduction is a powerful mechanism for influencing the oil in the low permeability matrix in a heterogeneous formation, and the characteristically thick pay sections often associated with carbonate reservoirs result in relatively low heat losses to the confining strata.

A numerical simulation model was used to study the effects of varying certain reservoir parameters (thickness, porosity, oil saturation, horizontal permeability, horizontal-to-vertical permeability ratio, well spacing and stratification) on performance parameters (steam-oil ratio, oil recovery and project life). Steam-oil ratios less than 5-1/2 and recoveries greater than 80% in the heated zones were predicted for certain ranges of these parameters that are realistic for some carbonate formations.

Two methods of heat scavenging were investigated using numerical simulation and physical models. The more promising method was simply drawing down the reservoir pressure by continued production after stopping steam injection, thereby generating steam by water flashing in the heated zone. This reduced steam-oil ratio by about 1-1/2 units in our test case, relative to continued steam injection, with only slightly reduced recovery and slightly increased project life.
An Analysis of Predicted Versus Actual Gas Injection Performance of the Williams Reservoir, Coleman County, Texas
Authors: Runyan E.E.
Published: December 2007

In the Williams field reservoir study, the predicted performance agrees very well with the actual performance. The oil recovery was predicted almost exactly, the pressure performance was predicted closely, and the gas-oil ratio performance was approximated. Each of the last two factors was thrown in error since wells were shut in as they went to a high GOR. This practice had not been allowed for in the original reservoir study but became a necessity when it was found impossible to market the excess produced gas.

Introduction

It is the purpose of this paper to apply the accepted reservoir engineering methods of predicting the behavior of closed reservoirs to the Williams field and to compare these predicted results with those actually obtained under gas injection. It is hoped that this comparison, with the original reservoir study based on information available only up to the time of initial gas injection, will indicate the accuracy obtainable in predicting the behavior of this type of reservoir.

Discovery, Development and History

The Williams field was discovered in Nov., 1943 by Hunter and Hunter Oil Co. of Abilene, Tex. in what is now the Williams unit 3. The discovery well was completed in the Gray sand for an initial potential of 8 BOPD with a GOR of 116,000 cu ft of gas/bbl. Development proceeded at a moderate rate with 14 wells drilled in 1944 and 13 in 1945. Five wells were dry and two were completed in a small separate reservoir to the west of the main reservoir. All wells were drilled with rotary tools and spacing followed a nearly regular 40-acre pattern.

Completion practices included setting 100 ft of 10 3/4 in. surface pipe, drilling to the top of the Gray sand, coring the entire pay interval, logging, and setting a 5 1/2 in. production string through the gas cap. Therefore, all wells are producing from the open hole.
A New Mechanical Pile Connector Speeds Offshore Construction Projects
Authors: Hettinger F. L.
Published: December 2007

During the past year, a new mechanical pile connector has been introduced to the offshore construction industry. This connector has been the culmination of an extensive development and fullscale testing program by Vetco Offshore, Inc. A family of driveable pile connectors has since been produced, ranging in size from 30" O.D. to 72" (762 mm to 1829 mm). Included in this family are standard releasable connectors and remote-releasable connectors for skirt pile recommended for permanent pile applications.

Specifically designed for skirt pile and permanent pile applications, the pile connector incorporates field-proven features that have been used on Vetco wellhead and riser connectors. The design phase included a finite element optimization and a fatigue analysis of the connector. Special anticorrosion considerations have been taken to ensure long life in the marine environment.

The connector was tested extensively at both in-plant and field facilities. These tests included tensile, pressure, bending functional, and pile driving tests. Following the development tests, the connector was supplied to several users for actual field trials. Since the connector has been introduced to the offshore industry, it has been used in a variety of skirt piles and permanent pile applications. To date, the pile connector has been supplied in 30",40", 42", 48", 54"and 72" (762 mm, 1016 mm, 1067 mm, 1219 mm, 1372 mm and 1829 mm).