bluuebunny/crossref_metadata_2025 huggingface dataset:
A Particle Sizing Technique Using Rayleigh Backscattered Ultrasonic Waves
Authors: Maharidge Russell L.
Published: December 2007

An ultrasonic technique, based upon Rayieigh scattering, is described for calculating the size distributions (2–10μm dia.) of low concentrations of particles in water from the amplitude measurements of backscattered acoustic pulses. Results of the particle size distribution calculations agree well with the size distributions measured with a Coulter counter. This technique was applied to particle systems that had identical material properties and size distribution functions which decreased with increasing size. With further development, this method may provide valuable solids content and size distribution information in source waters that are injected during waterflood operations.
Hydrogen Generation During In-Situ Combustion
Authors: Hajdo L. E. , Hallam R. J. , Vorndran L. D. L.
Published: December 2007

BP Resources Canada Ltd. is operating an oxygen in-situ oil recovery pilot at Marguerite Lake, part of the Cold Lake heavy-oil deposit in eastern Alberta. The pilot consists of two principal areas: a three-well, wet air combustion test and an infill-drilled, four five-spot, wet oxygen combustion project on 2 hectare spacing (5 acres). All the wells were initially steam fractured and steam operated through several cycles. Thereafter, selected wells were converted to air or enriched-air i njectors.

Eight adiabatic combustion-tube tests were conducted at the University of Calgary on reservoir materials under various conditions. During several, but not all, of the tests small amounts of hydrogen gas were produced in a discontinuous fashion. In contrast to this, most wells in the field have produced hydrogen, some consistently as high as 20 mole percent.

The present study was undertaken in order to better understand the flow and reaction processes that generate hydrogen in situ and thereby to suggest ways of influencing its production. The results are interpreted in terms of five reaction processes involving hydrogen: aquathermolysis, thermolysis, coke gasification, the water-gas shift reaction and methanation.

It is concluded that the hydrogen is generated by the coke gasification reaction followed by the water-gas shift reaction. Methanation processes also play an important role. Thermal cracking is a minor contributor to the gas production and aquathermolysis is negligible.
Well Testing in Low-Transmissivity Oil Reservoirs
Authors: Kabir C. S. , Kucuk F.
Published: December 2007

Well testing in a heavy-oil reservoir, characterised by low transmissivity, involves a long testing time because of long-duration wellbore storage effect. In some cases, several weeks may be required to reach the correct semilog straight line on the Horner graph.

This long-duration storage could be significantly reduced if a well is allowed to build up against the atmospheric pressure rather than the increasing shut-in wellhead pressure as commonly practised. Such a test could be easily conducted on a pumping oilwell. The procedure involves turning off the pump, opening the casing-head valve to atmosphere, and monitoring the rise of the annular liquid level with an acoustic well sounder (AWS). Measurement of the continuously moving annular liquid column provides both the bottom-hole pressure and the downhole rate during the buildup period. In other words, AWS data are translated to bottomhole pressures and downhole rate needed for transient analysis.

Field data indicates that a test conducted in this manner reduces the testing time to a fraction of the time required for a conventional test. A true static reservoir pressure (p¯) is attained in a very short time; consequently, uncertainty of correcting Horner's p* to p¯ is avoided. In essence, semilog straight line begins much earlier when the proposed testing technique is adopted.

This study attempts to reduce the wellbore storage distortion period in a pumping oil well test in two ways. First, we consider the convolution and deconvolution treatments of test data. Second, we propose a test technique that accelerates a pressure buildup process. The proposed technique is however limited to wells not capable of flowing to the surface upon shut-in. This imposed constraint is strictly based on practical considerations associated with such a test, and is not a limitation of the model considered in this work.
Use of Pressure Falloff Tests To Locate the Burning Front in the Miga Field, Eastern Venezuela
Authors: Da Prat G. , Bockh A. , Prado L.
Published: December 2007

A study was made to determine the burned volume and the location of the firefront in the Miga P2,3 in-situ combustion project (Eastern Venezuela). This study was based on pressure fall-off data taken with a high resolution crystal pressure gauge with an automatic data acquisition and processing system. The importance of it lies in the fact that besides verifying, from a practical viewpoint, the predictions of the theoretical models available for composite systems, it shows some of the pitfalls associated with the use of quartz crystal pressure gauges.

A critical analysis of the observed pressure vs time data revealed some anomalies which may be associated with temperature effects in the pressure probe.

The actual pressure vs time data matches quite well the predictions made with a composite system model, and, therefore, the values obtained for the burned volume and the location of the burning front are believed to be reliable.
Khuff Development: Overview
Authors: Fathaila M.
Published: December 2007

The development of the Khuff Reservoir in Bahrain and the Gulf as a whole started way back in 1947, when crestal Well 52 in the Bahrain Field was deepened to discover the Khuff Reservoir at a depth of 10078'. In the hope of finding an oil column associated with the gas found in crestal Well 52, Wells 88 & 128 was drilled on the east and West flanks respectively with no show of oil in either of them.

At that time there was a limited source of rich gas in Bahrain from the relatively shallow zones of Arab A & C feeding the refinery and a power plant and consequently there was no requirement for an additional source of gas and as such the development of the Khuff Reservoir was stopped.

In the late sixties the Bahrain Government managed to interest investors to build an aluminium plant. The viability of the project was partly based on the availability of an abundant and reliable source of natural gas reasonably priced. Well 254 and 255 were drilled in 1969 specifically for this purpose. These two wells were followed by other wells, initially two at a time, to meet the continuous demand for the power sector and industrial use. We are at present at the final stages of a ten well program which will bring the total number of wells drilled and completed to 21 by Mid 86. The whole demand for gas on the island is ncw supplied from the Khuff and associated gas which is mostly cycled Khuff gas. The Arab gas reservoirs were shut-in in early '74 for conservation.
Improvement in Drilling Performances Through Nine Khuff Wells
Authors: Al-Busaidi H. , Du Charlat A. Peyredieu , Rouatbi R.
Published: December 2007

ADMA-OPCO drilled its first deep Khuff well using various types of tooth and diamond bits at very high cost/ft. Through various trial runs, turbodrilling with diamond and polycristalline bits proved to be most efficient method to drill the 12 1/4" & 8 3/8" phases.

By using the right bit programme and reducing the sticking problems, a dramatic improvement in ROP and average cost/ft was achieved.
Design and Techniques of Testing and Evaluation of Deep Khuff Wells
Authors: Al Khatib M. A. , Sadik A. S.
Published: December 2007

Three deep Khuff wells have successfuly been tested by ADCO. Formations tested were at 16,000-21,000 ft, where bottom hole temperatures and pressures reached 440°F and 0.64 psi/ft. The Khuff wells tested, the completion design needed for hostile service conditions, the testing techniques and the equipment used in stimulating and producing formation fluids at surface are described in this paper.
Formation, Distribution, and Prediction of Stylolites as Permeability Barriers in the Thamama Group, Abu Dhabi
Authors: Burgess C. J. , Peter C. K.
Published: December 2007

Stylolites and associated pressure dissolution phenomena are common features of most carbonate reservoirs but their effects on reduction of porosity and permeability are variable. In chalky limestones such as the Thamama Group of Abu Dhabi stylolites may cause a reduction in permeability sufficient to create a barrier to fluid movement.

Most stylolites result from dissolution of carbonate as a result of overburden pressure. Dissolution occurs along pre-existing surfaces within the rock and in particular along bedding planes. The presence of even small amounts (<1%Rv) of clay material in the rock encourages stylolite development. Thus in a sequence of uniform, laterally persistent lithofacies such as occur in the Thamama II and IIIa zones, stylolites may be similarly distributed and form field-wide vertical permeability barriers. In view of the relationship between stylolites and depositional lithofacies, prediction of their distribution may be made by core and log study and depositional modelling.

In an Offshore Abu Dhabi field, an attempt has been made to predict vertical permeability through stylolite zones in uncored wells. Comparison of the stylolite intensity index, calculated from FDC/CNL logs following the method of Johnson and Budd (1), with measurements from whole core and plug analyses showed that a statistically valid relationship exists between these two parameters. Separate relationships have been established for stylolites above and below the oil/water contact as values in the water zone tend to be further reduced by continued cementation. The establishment of these relationships has enabled the prediction of vertical permeabilities through stylolite zones in uncored wells. Vertical permeabilities of less than 1md equate to a stylolite intensity index of 50, and in the subject field such zones are likely to severely limit fluid movement. Such geological analysis can thus provide a useful model for aiding reservoir simulation and field development.
An Overiew of In-Situ Methods for Determining Remaining Oil Saturations
Authors: Blackwell R. J.
Published: December 2007

This paper reviews the relative advantages and disadvantages of the following methods for measuring the remaining oil saturation (ROS): pressure coring, sponge coring, the single-well tracer method, and PNC, C/O, electric, EPT and NML logging methods. Careful planning and execution by well-trained personnel is considered mandatory for the field application of these methods.
Skin Effect and Completion Options in the Ras Budran Reservoir
Authors: Harper T. R. , Moftah I.
Published: December 2007

High positive skin factors were encountered in early production wells drilled in Unit I of the Nubian Sandstone reservoir of the Ras Budran oil field. Laboratory tests and theoretical analyses were conducted, from which it was concluded that the observed skin factors could not be explained by conventional formation damage mechanisms. Alternative mechanisms are proposed, based upon the presence of low permeability quartz-filled fractures. These give rise to a heterogeneity. Types of completion potentially able to improve well productivity are identified.
Stimulating Very Long Gross Intervals
Authors: Blinten J. S. , Aziz R. M.
Published: December 2007

Conventional acidizing and fracturing techniques are not applicable when very long gross intervals on the order of 1,000 to 3,000 feet are to be stimulated. Concepts such as fracture length and improved wellbore radius have little meaning in such cases since it is very difficult to predict or control the placement of stimulation fluids. Good diversion of fluids is the controlling factor for successful stimulation of very long gross intervals. The problem is compounded when long net intervals on the order of 500 to 1,000 feet are to be stimulated within these very long gross intervals. In such cases, the surface injection pressure required for conventional limited entry techniques can be prohibitive. These problems often can be solved by stimulating with high injection rates, buoyant ball sealers, and limited perforations.

Amoco Sharjah Oil Company has encountered these problems in attempting to stimulate the Thamama in Sajaa Field. A brief history of Amoco's experience in Sajaa Field with mechanical isolation and various diverting agents is presented. To date, 6 wells have been stimulated by using high injection rates, buoyant ball sealers, and limited perforations. Some of these jobs have contained the largest fluid volumes ever injected in the Middle East and at the highest rates attempted. The results of this technique have been encouraging. The job design, equipment requirements, fluid formulations, and results of these stimulations will be presented.
Horizontal Wells Production Techniques in Heterogeneous Reservoirs
Authors: Giger F. M.
Published: December 2007

Two advantages of oil production with horizontal wells are the increase in productivity of each well and a new approach to solving reservoir-engineering problems resulting from heterogeneities. The aim of this paper is to propose elements of analysis focusing on flowline patterns and pressure distribution in an oil field. These elements should be of help to decision-makers when faced with an economic choice between spudding vertical or horizontal wells and eventually fracturing them.
Increasing Casing Collapse Resistance Against Salt-Induced Loads
Authors: Khalaf F.
Published: December 2007

Casing collapse opposite Salt formations is a real field problem. Several solutions are proposed for this problem. This paper presents an analysis of three of these solutions, namely thick-walled pipe, high collapse resistance casing and multiple strings packed with cement. The strength of each solution and its effects on the drilling and completion practices are also discussed. The mechanical resistances to uniform and point loads of the multiple strings and thick walled pipe are superior to those of a high collapse solitary string.
The Tazerka Floating Production, Storage, and Offtake System
Authors: Ballard P. G.
Published: December 2007

Production from small oil reserves found offshore which would be uneconomic on the basis of a conventional approach have been developed by utilising a Floating Production Storage Unit permanently moored to the seabed by a Single Anchor Leg System. The storage unit not only supports the production facilities but also acts as the offshore terminal, thus offsetting the cost of a pipeline and shore terminal. In addition to the use on small reservoirs, a similar installation may also be utilised for the early production of large offshore oil accumulations and in both cases, retains the advantage that a major part of the investment can be redeployed elsewhere when the field has been exhausted or permanent facilities have been installed.

This paper describes a system installed offshore Tunisia by Shell Tunirex but unlike other floating production systems, it has the capability of tying in several sub-sea completed wells. In addition, it has the flexibility to cater for additional wells or functions, such as gas lift or water injection, should they be required to optimise oil recovery later in the field's life.
Core-Annular Oil/Water Flow: The Turbulent-Lubricating-Film Model and Measurements in a 2-in. Pipe Loop
Authors: Oliemans R. V. A. , Ooms G. , Wu H. L. , Duijvestijn A.
Published: December 2007

Core-flow tests with a 3000 mPa.s fuel oil in a 2-inch test facility have revealed important information on the amplitudes and lengths of waves at the oil/water interface. The wavelengths vary considerably with water fraction and oil velocity. Moreover, the flow in the water annulus is turbulent. A previously developed theoretical model for steady core-annular flow in pipes has been extended by incorporating the effect of turbulence in the water film surrounding the oil core. Core-flow pressure gradients predicted by the adapted model coincide very well with measurements provided that actual wave amplitudes and wavelengths observed during these tests are used as input data.
Utilisation of Gas Resources in Qatar: A Decade of Planned Development and Integration
Authors: Ferdrin J. P.
Published: December 2007

Qatar's demand for energy has increased tremendously during the last decade due to expanded economic activity since the early 1970's and subseguent diversification through development of downstream industries. Most of the energy requirement is met by natural gas.

The purpose of this paper is to describe the development of a gas oriented producing country and the operating philosophy for maintaining maximum efficiency and preserving the Nation's natural resources.
Debottlenecking of Acid Gas Removal Units
Authors: de Fraissinette C. , El Komy O. F. , Piquet F.
Published: December 2007

The Abu Dhabi Gas Liquefaction Company (ADGAS) has since 1977 operated the only gas liquefaction plant in the Middle East producing simultaneously LNG, LPG and Pentanes. The Plant processes the associated gases from Abu Dhabi offshore oil fields as well as non associated gas. This is the only LNG facility in the world operating on associated gas.

The gas composition of the 11 different feed streams supplying the LNG plant varies broadly and for instance the sour gas content (CO2+H2S) of each stream can vary between 3.3% and 34%. An average gas stream composition supplied to the Acid Gas Removal Unit is given in Table-1.

The Plant consists of two identical process trains in parallel arranged to permit safe overhaul of one train while the other remains in service.
Conception and Construction of an LPG Tank Using a Composite Membrane Technology
Authors: Fuvel P. , Claude J.
Published: December 2007

TECHNIGAZ and TOTAL C.F.P. have developed a new LPG storage technology derived from the membrane concept used for LNG storage and transportation.

This technology called GMS uses a composite membrane as primary barrier. A 2 000 m3 storage pilot unit, based on that concept, is under construction in TOTAL'S refinery at DUNKIRK (France) since September 1983.
Offshore Refrigerated LPG Loading/Unloading Terminal Using a CALM Buoy
Authors: Bonjour E. L. , Simon J. M.
Published: December 2007

In existing Liquefied Petroleum Gases terminals, the transfer of liquefied gases to the tanker is performed via articulated loading arms or flexible hoses, working under quasistatic conditions. The tanker has to be firmly moored alongside a jetty or a process barge in a protected area (such as a harbour in most cases).

This paper gives the main results of the development of an offshore refrigerated LPG (−48° C) loading / unloading system, using a CALM buoy and LPG floating hoses working under dynamic conditions. The aim of this new concept is to replace the standard harbour structure for loading /unloading refrigerated LPG and to provide: –a considerable reduction in investments;–a greater flexibility regarding the terminal location.

The main components of that terminal have been designed so as to enable the loading of a 75 000 cubic meter LPG carrier in 15 hours. The results of static and dynamic low temperature tests on a LPG swivel joint for CALM buoy and LPG floating hoses show that such a SPM terminal is now a realistic solution.
Formation Damage Prevention through the Control of Paraffin and Asphaltene Deposition
Authors: Newberry M. E. , Barker K. M.
Published: December 2007

Formation damage caused by the precipitation and deposition of paraffin or asphaitene particles has been a recurrent problem in the production of crude oil.

A number of well established oilfield operations have been found to aggravate these organic deposition problems. Laboratory testing of crudes and chemical additives has led to a number of solutions to these problems. Case history information on testing, chemical application, and subsequent field results are presented.
Parameters Affecting Fracture Design and Their Measurement During Treatments
Authors: Pearson C. M. , Abou-Sayed I. S. , Nguyen N. B.
Published: December 2007

This paper shows how an understanding of the relative influence of fracture design parameters, and treatment procedures enable the engineer to improve hydraulic fracture results. The measurement of a few critical parameters provides a better understanding of fracturing in a particular formation.

Results are presented from a joint program of research carried out between Gulf Research & Development Company and Gulf Oil Exploration and Production Company during 1984. The principal objectives of this program were to obtain improved field data for the verification of fracture simulators, and to investigate the field measurements and analysis of parameters found to significantly affect design. Emphasis is placed on understanding the effect of reservoir properties on the created fracture and the required fracturing pressure. This information was then used in the field to optimize limited size treatments in particular formations.
Pressure Fluctuating Tool
Authors: Payne R. A. , Williams K. A. , Pelty L. L. , Bailey H. L.
Published: December 2007

The Pressure Fluctuating Tool (PFT) utilizes a fluidic oscillator to create pulsating pressure for breaking down perforations. The maximum pressure fluctuations produced by the oscillator can be as great as 1500 psi (10,300 kPa) above and below downhole ambient pressure with frequency ranging from 140 to 160 cycles per second. Pressure fluctuations are greatest in the primary oscillation zone located at the center of the 26 foot.(7.92m) long tool. The pressure fluctuations decrease to essentially zero within 8 feet (2.43m) above and 8 feet (2.43m) below the primary oscillation zone. These fluctuations break down the perforations and formation face.

As perforations are opened, the casing annulus is effectively exposed to a larger fluid volume, causing the amplitude and frequency of fluctuations to decrease. These changes are monitored by instrumentation at the surface to determine when breakdown is complete and the tool can be moved to the next section of perforations.

This paper will describe the operation of the PFT and report data collected in field applications.
Electrical Submersible Pump Performance Using Variable Speed Drives
Authors: Wilson B. L. , Liu J. C.
Published: December 2007

Variable speed drive units (VSD) designed specifically for use with electrical submersible pumps (ESP) have been available for several years. The ability to vary the operating speed of the ESP greatly expands the operating range of the unit. To take full advantage of the capabilities of an ESP operating on a VSD, it is necessary to understand the concepts of sizing and the operational limitations of the equipment.
Tubing Protection and Design for Corrosive Environment
Authors: Hayatdavoudi A. , Altunbay M.
Published: December 2007

Present methods of corrosion mitigation, although successful and advantageous over past methods, appear to be highly overdesigned and thus prove to be expensive.

In order to reduce the cost of corrosion control, the authors have proposed a series of calculation steps that limit the corrosion control to specific intervals of tubing rather than the whole string of tubing. Further cost saving measures can be realized by completing the corrosive wells with a system that monitors corrosion and regulates the mass flow rate of inhibitor into the tubing automatically.
Field Investigation Identifies Source and Magnitude of Iron Problems
Authors: Gougler P. D. , Hendrick J. E. , Coulter A. W.
Published: December 2007

Recent field studies indicate that iron may be a problem in acid stimulation, even in formations that do not contain iron minerals. A program was undertaken to identify the sources of iron that may be carried by fluids used in well stimulation. While possible sources have been suggested by many investigators, this program was conducted on well sites where acid was pumped out of typical steel tanks, through conventional blending and treating equipment and well tubulars. Sources of iron encountered were identified by monitoring at multiple points in the process. A surprisingly high concentration of iron was found in the first portion of the acid passing through the system.
New Conductivity Found in Angular Blends of Fracturing Sand
Authors: Larsen D. G. , Smith L. J.
Published: December 2007

Recent tests have shown that the conductivity of a 20-40 sand pack is increased by blending angular sand with the very round product currently used in hydraulic fracturing. The oil and gas industry requires fracturing sand to meet high roundness specifications, according to the Krumbein and Sloss chart, for the purpose of providing the optimum geometric pack in the fracture. Indeed this will decrease point pressure on the sand grains and reduce crushing and fines generation in the sand pack, but tests indicate that the optimum geometric pack for crush resistance does not always offer the maximum conductivity through a sand pack.

Sand grains with a roundness factor of .5 (the minimum API standard for frac sand is .6) were mixed in 50/50, 62.5/37.5, 75/25, 87.5/12.5 and 100/0 blends with sand grains having a roundness factor of .8. These combinations were placed in a conductivity cell and tested at closure stresses as high as 10,000 psi. Several blends proved more conductive than the 100% highly rounded grains used as a control sample. This paper will show how the increased void space of a round-angular sand combination overcomes its susceptibility to crushing and provides increased conductivity, the most reliable measurement of a sand's overall performance.
Optimization of Fracture Fluid Recovery and Production Through the Use of a New Stimulation Technique
Authors: Phillips A. M. , Wilson W. J.
Published: December 2007

A technique for improving stimulation fluid recovery has been developed in the laboratory and has proven effective in field applications. The method involves improving proppant pack drainage and minimizing capillary pressure in the formation through the judicious application of surface active agents.

The technique is particularly applicable in low pressure oil wells and tight gas reservoirs, and may be used in all aqueous fracturing treatments. These include slick and gelled water, as well as foamed and crosslinked systems. The technique involves the use of a solvent in the pad fluids and a surfactant system throughout the entire fracturing treatment. This combination improves sand pack drainage and minimizes capillary water blocks in the invaded formation, while maintaining the water-wet condition of both the proppant pack and formation.

The results of field applications using this technique have shown great improvement in the recovery of aqueous stimulation fluids in both sand and limestone formations. Increases in initial hydrocarbon production have also resulted. Case histories are presented from both oil and gas wells in a variety of formations.
Successful Stimulation of the Olmos Formation Using Oil-Base Fluids and High-Proppant Concentrations
Authors: Pauls R. W. , Venditto J. , Chisholm P. , Holtmyer M. , Gregorcyk W.
Published: December 2007

Successful stimulation of the Olmos Formation in McMullen County, Texas, has proven to be challenging. Initial attempts at fracturing the Olmos using water-base fluids and low proppant concentrations did not prove to be very successful. Core studies have indicated this formation to have a fluid retention tendency. Gelled hydrocarbon fluids with high sand concentrations are now being used as a fracturing system with significantly improved success.

The transition to gelled oils capable of carrying high sand concentrations has presented some unique challenges to the industry because portions of the Olmos Formation are at depths approaching 10,000 ft [3050 m] with bottomhole temperatures to 259°F [126°C]. The most successful fracturing treatments in the Olmos appear to result from long fractures propped with high concentrations of propping agent. The long fractures contact additional reserves and the high sand concentrations not only produce highly conductive fractures but also settled bank heights capable of filling the fracture below and through the Olmos zone. Fluid viscosities required for these treatments were based upon pre-fracturing analyses and computer evaluations, which determined fluid efficiency and fracture closure times. This posed a problem as the commonly available oil-based fracturing fluids either did not have sufficient fluid viscosity downhole over extended periods at high temperature (at least six hours at 259°F [126°C]) or, if they did meet this requirement to place the proppant, were too viscous on the surface into which high concentrations of sand could be mixed or be easily handled with surface equipment.

To date, in excess of 60 wells in the Olmos have been treated successfully using high sand concentrations and a new method for gelation of oil-base fluids. This method involves use of enough gelling agent to gel the hydrocarbon for the required surface viscosity and downhole stability, and also provide the needed amount of activator for surface conditions. The activator concentration can be varied to produce a base gel which is easily pumped and into which the propping agent can be easily mixed. As this base gel is being pumped downhole, additional activator is added to produce a gelled fluid needed for downhole conditions. Treatments in the Olmos have evolved up to 1,800,000 pounds [816,500 Kg] of 20/40 mesh Ottawa sand and 250,000 gallons [946 m3] of gelled fluid. Jobs are pumped at 12 bbl/min [114 m3/sec] for up to 10 hours, averaging 12 lb of sand/gal of fluid [1400 Kg of sand/m3 of fluid] with a maximum concentration of 17 lb of sand/gal of fluid [2000 Kg of sand/m3 of fluid]. The wells so treated have responded with more sustained production than wells treated with less temperature stable fluids containing lower concentrations of sand.

Laboratory studies, treatment methods, completion and production data will be presented.
Computer Graphics-Aided Systems Analysis: Application to Well Completion Design
Authors: Detamore J. E. , Sharma M. P.
Published: December 2007

The development of an engineering tool (in the form of a computer model) for solving design and analysis problems related with oil and gas well production operations is discussed. The development of the method is based on integrating the concepts of "Systems Analysis" with the techniques of "Computer Graphics". The concepts behind the method are very general in nature. This paper, however, illustrates the application of the method in solving gas well completion design problems. The use of the method will save time and improve the efficiency of such design and analysis problems. The method can be extended to other design and analysis aspects of oil and gas wells.
The Travis Peak (Hosston) Formation of East Texas and North Louisiana
Authors: Saucier A. E. , Finley R. J. , Dutton S. P.
Published: December 2007

The Travis Peak Formation (Hosston Formation in Louisiana) is a basinward-thickening wedge of terrigenous clastics that extends in an arc from eastern Texas across southern Arkansas and northern Louisiana into southern Mississippi. This formation is a large reservoir of natural gas that is contained in sandstones of low permeability that are generally classified as tight gas sands. Because of the stratigraphic complexity and past limited economic interest in this Lower Cretaceous formation, little is known about the distribution or depositional environments of potentially productive sandstones within it. This subsurface study of the Travis Peak (Hosston) and Sligo Formations utilized 1,300 electric logs distributed across an area of approximately 35,000 mi2 covering the east half of the East Texas Basin, the North Louisiana Basin, and part of southern Arkansas.

In addition to the standard isopach and structure maps, several lithofacies maps and six semi-regional stratigraphic cross sections made it possible to recognize the following five depositional systems in the Travis Peak (Hosston) Formation: fluvial-deltaic, delta fringe, restricted marine shelf, shelf margin, and open marine. The most sand-rich systems are the fluvial-deltaic and the shelf-margin systems.

Two major high-constructive delta complexes have been identified in the study area. These deltas were located over the present sites of the Sabine and Monroe Uplifts. The North Louisiana Salt Basin, a marine embayment in Travis Peak (Hosston) time, accumulated a thick section of interbedded shales and limestones in a restricted back-reef or back-bar shelf area. A carbonate or sandstone barrier appears to extend across the central Louisiana Early Cretaceous shelf margin.

The delta-fringe system, although containing less sand, consists of a variety of lithofacies deposited in a transition zone ranging from delta-plain to shallow-marine-shelf environments, and it appears to correlate with the most hydrocarbon-productive part of the Travis Peak (Hosston) Formation. Oil and gas accumulations in the Travis. Peak (Hosston) are closely associated with salt-cored structures in East Texas and North Louisiana. This study should aid in the projection of prospective tight gas trends.
Models of Heat Transfer in Hydraulic Fracturing
Authors: Ben-Naceur K. , Stephenson P.
Published: December 2007

The influence of heat-transfer mechanisms during fracture propagation is determined using a general model combining convection along the fracture with conduction and convection in the reservoir. A series of simplified models is also given, together with their ranges of applicability. The thermal simulator is coupled with a fracture propagation model, the rheology of the fracturing fluid being assumed to be time- and temperature-dependent. Implications of the heat-exchange processes on the proppant transport in the fracture and on the post-stimulation well performance are given.
In-Situ Stress Determination From Wellbore Elongation Measurements
Authors: Blanton T. L. , Teufel L. W.
Published: December 2007

This paper explores the feasibility of making in situ stress measurements at depth from caliper measurements of deformed wellbores. The work has been carried out in three steps: (1) theoretical development of viscoelastic constitutive equations necessary for calculation of stress directions and magnitudes, (2) application of the equations to field data, and (3) comparison of results to stress measurements made by hydraulic fracturing and overcoring methods. The results of the theoretical analysis are equations that relate the minimum and maximum radii of a deformed wellbore to the maximum and minimum stresses perpendicular to the axis of the wellbore. Calculation of absolute magnitudes of stresses requires the viscoelastic compliance and Poisson's ratio of the rock, but even when this information is not available relative magnitudes of stresses can be determined. The constitutive equations were applied to caliper measurements of a horizontal borehole in unwelded ash-fall tuff near an underground tunnel complex in Rainer Mesa on the Nevada Test Site. The horizontal borehole was aligned in the direction of the maximum horizontal stress. Over a 37 day period the wellbore showed time-dependent deformation, with maximum closure in the maximum stress direction (overburden). The ratio of principal stress calculated from caliper measurements of the deformed wellbore varied from 1.73 to 2.06, depending on the time interval used. The ratios obtained from overcoring and hydraulic fracturing were 1.79 ± .22 and 2.12 ± .12. Limitations of this approach to stress measurement are discussed, but results of the present study suggest that with further development of the viscoelastic consitutive model, stress variations along the length of the wellbore might be readily examined as part of the well logging process.
Capillary Pressure and Permeability Relationships in Tight Gas Sands
Authors: Wells J. D. , Amaefule J. O.
Published: December 2007

An improved technique for determination of the Swanson Petrophysical parameter, (Sb/Pc)A for correlating permeability with capillary pressure data has been developed. (Pc/Sb)1/2 as a function of Sb, yields a well defined minimum which corresponds to the values of Pc and Sb from the Swanson graphical method. The improved technique leads to ease of computer determination of the parameter. The relationships developed by Swanson for correlating permeability with capillary pressure work well for samples with permeabilities greater than 10 microdarcies. A new relationship between the Swanson parameter and permeability has been developed for tight gas sands which leads to a more accurate permeability prediction below 10 microdarcies.

Mercury capillary pressure data at wetting phase saturations higher than 50% are approximately a factor of 10 greater than centrifuge air-brine capillary pressure for tight gas sands. This contrasts with the more commonly assumed value of 5. Consequently gas-water relative permeabilities computed from mercury injection capillary pressure data will result in predictions of higher water-gas ratios than the air-brine data. Optimistic cleanup times for tight gas wells completed in water-base fluids would, therefore, be deduced from the mercury injection data.
A Stimulation Method for the Codell Sandstone, Denver-Julesburg Basin of Colorado, Using Low pH Methanol
Authors: McLane J. E. , Edgington L.
Published: December 2007

The clay filled low permeability sandstone of the Codell formation of Colorado has historically been a difficult formation to stimulate. In the past, conventional methods of stimulation have been used in the Codell sandstone with results below expectations.

Codell sandstone core samples were taken from several wells in the Denver-Julesberg Basin of Colorado, over a three county area, and were from various depths of approximately 1554.50m (5100 ft.) to 2438.40m (8000 ft.)

The object of this paper is to characterize the Codell sandstone cores by use of Scanning Electron Microscopy and Energy Dispersive Spectrometry (SEM/EDS) to evaluate the mineralogy and lithology of the formation. The samples were then subjected to experimental and conventional treatment fluids by use of a Gas/Liquid Reference Core Flow Apparatus to determine the least damaging stimulation treatment.

Treatment fluids evaluated in this study were: 100% methanol, low pH methanol with specific additives, KCl water/methanol blends, KCl water and various weak acid blends. One of the low pH methanol systems described in this paper has shown positive gains in permeability during core flow testing and can be an effective enhancement of conventional water based systems used for stimulating other low permeability reservoirs. The most effective method of application of such a system has been as a prepad ahead of conventional water base treatments.

The concept of low pH (4.0) methanol combined with a special silt suspension and clay control chemical additives is suspected to partially dissolve and/or reduce the size of the various clay components in the immediate wellbore vicinity where maximum leak-off/spurt-loss damage usually occurs.

Case histories from treatments done in the DJ Basin will be discussed and evaluated.
Integration of Laboratory and Field Data for Insight on the Multiwell Experiment Paludal Stimulation
Authors: Sattler A. R. , Raible C. J. , Gall B. R.
Published: December 2007

Two stimulation operations have been conducted to date in the paludal zone of the Mesaverde formation in one well, MWX-1, at the DOE's Multiwell Experiment test site in the Piceance Basin near Rifle, Colorado. Problems were encountered in the second stimulation: MWX-1 would not sustain production for several months and post-frac production was less than pre-frac rates. The laboratory program was expanded to examine these problems and these laboratory studies were integrated with well testing and other data to help explain MWX-1 production behavior. A unique explanation cannot be found for the failure of MWX-1 to produce; a combination of factors was responsible. Water probably inhibited matrix rock production. A system of naturally occurring microfractures is important in production from the paludal zone and it probably sustained damage by water and fracture fluids. The basic gel degraded slowly because only a small amount of breaker was used. The fracture closure (viscosity break) observed from the Nolte analysis of the stimulation was not the same as the breakdown of the basic gel. The remedial treatment conducted after the second stimulation was probably too reactive. A list of items has been developed from experience gained both inside and outside the laboratory that shows what work and which procedures should be emphasized or avoided in tight sand stimulations.
Impedance of Hydraulic Fractures: Its Measurement and Use for Estimating Fracture Closure Pressure and Dimensions
Authors: Holzhausen G. R. , Gooch R. P.
Published: December 2007

The growth of a hydraulic fracture increases the period of free oscillations in a well. Simultaneously, the decay rate of free oscillations decreases. The properties of forced oscillations in a well also change during fracture growth. All of these effects result from the changing impedance of the hydraulic fracture that intersects the well. Fracture impedance can be determined directly by measuring the ratio of downhole pressure and flow oscillations, or determined indirectly from wellhead measurements using impedance transfer functions. Because impedance is a function of fracture dimensions and the elasticity of the surrounding rock, impedance analysis offers a promising new approach for evaluating fracture geometry. Because oscillatory flow conditions occur continuously a hydraulic-fracturing treatment, data collection is simple and economical, adding to the attractiveness of this technique.
Laboratory Formation Damage Studies of Western Tight Gas Sands
Authors: Raible C. J. , Gall B. L.
Published: December 2007

This laboratory study, using formation cores, addressed problems associated with restoration of gas permeability in core from tight gas sand formations after massive hydraulic fracturing (MHF) treatments. Parametric studies affecting the flow of both brine and gas in these formation cores included the effects of the pressure differential across the fluid invaded zone, permeability, temperature, and gel damage to the fracture surface. Formation damage after exposure to fracturing fluids is primarily a problem of fluid recovery and water-saturation reduction.

Polymer damage to the fracture or fracture surface using Western tight gas sand cores caused significant brine permeability reduction and increased the fluid recovery time of the invaded zone. Increased fluid recovery time was magnified for very low permeability formations (less than 0.03 md) and low gas pressure differentials. Capillary end effects are postulated to be responsible for these results. However, after fluid saturations were reduced by displacement and evaporation, polymer damage to gas flow was less than 20 percent.

Results of this study indicate that as reservoir quality decreased there were greater capillary effects and extended time periods were required for invasion fluid recovery to attain maximum gas flow. By using cleanup time and regained gas permeability curves of saturated cores, these capillary effects were observable in the laboratory at reservoir conditions.
The Potential Role of Offshore Standby/Rescueships
Authors: McDonald H G
Published: December 2007

The loss of the drilling rig "Sea Gem" in 1966, in which thirteen people died, was perhaps the first occasion when a major accident connected with offshore explorations and production in the UK Sector of the North Sea resulted in multiple deaths. Since then, loss of life among offshore workers, either through major accidents or individuals falling overboard, has continued to occur throughout the various operational areas worldwide.

One method of increasing the survival chances of maritime casualties associated with offshore installations is to ensure that a designated rescue vessel is always available to attempt a rescue. At present in the UK, Regulation 10 of the Offshore Installations (Emergency Procedures) Regulations 1976, lays down that a standby vessel should be present within five miles of every manned offshore installation, ready to give assistance in an emergency, able to accommodate the entire crew of the installation, and provide aid for them all.

The requirement for a designated rescue vessel for every offshore installation has also been adopted by Norwegian legislators. In Canadian waters, there must be a vessel similarly designated; however, the specification guidelines for these craft are not nearly so detailed or rigorous. Other areas around the world where offshore exploration and development is, or will be taking place, also necessitate a degree of maritime rescue back-up. It is now generally accepted after incidents like the "Ocean Ranger" disaster, that, if it is agreed that a means of rescue from the sea has to be accounted for, then it must be of a specialist nature rather than a compromised attempt.
Safety and Environmental Auditing for Existing Offshore Facilities
Authors: Luck C J , Sellers J G
Published: December 2007

This paper describes a cost-effective approach developed by Arthur D Little to enable companies to identify the potential safety and environmental hazards of existing facilities, quantify the risks and develop risk mitigating measures. The paper highlights the differences in the approach needed for existing facilities compared with that normally used for safety assessment at the design stage. It shows how an effective audit can indicate very rapidly whether the situation is fundamentally safe or whether there are serious deficiences which will require a high level of effort to correct.
Techniques for Quantifying Formation Stress and Fracture Fluid Response for Optimum Hydraulic Fracture Design
Authors: Frisinger M. , Cooper R. E.
Published: December 2007

Improved fracturing treatment design has been achieved by computerised interpretation of the mechanical properties logs, laboratory rock properties measurements and production logging during minifrac tests. By combining these data acquisition techniques in a single well, optimum hydraulic fracturing design input information is obtained.

These techniques have been successfully used in a Southern Sector North Sea well. Subsequently, real-time and post-treatment evaluations have indicated the reliability of the technique.

Actual field data are presented showing use of these data. Also presented is a computer generated fracture geometry processed from mechanical properties log data. Due to the importance of accurate fracture geometry prediction in current North Sea gas field development, the techniques have proven to be a valuable aid.
An Engineering Critical Assessment – A Case History
Authors: Wheeler Dr M. F. , Baker N. J. , Shipley T. D. , Nelson S. G.
Published: December 2007

In order to allow for the development of the North East Frigg and Odin Gas Fields, an uprating of the Frigg Field Transportation and Treatment system was required. This uprating involved work on the Frigg Field, the North Sea Platform, Manifold Compression Platform Ol (MCP01) and the shore terminal at St Fergus in Scotland. The subject matter of this paper relates to the work carried out on MCP 01.

MCP 01, 110 miles offshore, is the centre of a gas collection system receiving gas from the Frigg, Piper and Tartan fields, and transporting this gas to the Total Oil Marine shore terminal at St Fergus. The Frigg gas comes to the MCP 01 by means of twin 32" diameter pipelines of API 5LX-65 material and that from the Piper/Tartan fields via an 18" diameter API 5LX-60 line. The gas is transported onshore via twin 32" diameter sub sea lines of API 5LX-65 material (Figure 1).

The maximum throughput of gas to St Fergus was in the region of 64 MCM/day and in order to carry the extra gas from the Norwegian sector it was required to install, on MCP 01, 2 × 28,000 MW compression sets. The installation of these compressors involved an upgrading of existing utilities and processing facilities, living accommodation and extra life saving appliances.