bluuebunny/crossref_metadata_2025 huggingface dataset:
Residual Oil Saturations Determined by Core Analysis
Authors: Kennaird T.
Published: December 2007

Residual oil saturation determined by several laboratory techniques on core plug specimens from a variety of lithologies in the Asia-Pacific region have been correlated to porosity, initial water saturation and permeability. To some extent, residual oil decreased with increasing initial water saturation and decreasing permeability. For the same mean hydraulic radius Kϕ residual oil left after gas-drive was much higher than that for a water-drive. On the average, residual oil saturation from steady-state water-oil relative permeability data were higher than those from the unsteady-state floods. This is an apparent reflection of the fact that steady-state floods are typically conducted at lower flow-rates than unsteady-state floods.
A Computer Aided Reservoir Engineering (CARE) System: From XY Plots to 3D Animations
Authors: Matsumoto M.
Published: December 2007

An advanced graphic post-processing system has been developed. The principal feature of this system is an three-dimensional(3D) expression of the whole reservoir phenomena as engineering animations. This system can show the distribution of parameters of the reservoir simulations by forming colored-transparent iso-value surfaces in the 30 space and the dynamic changes of the parameters by moving the surfaces smoothly with interpolation of the data between calculated time steps. Furthermore, it can create a contour map on an arbitrary cross section of the reservoir. The system is applicable to presentation and instruction as well as to result evaluation.
Waterflood Development of the Guntong and Tabu Fields
Authors: Hui S. K. , Pillai H.
Published: December 2007

Two oil fields which are characterized by weak natural pressure support and unfavorable rock properties were planned for waterflooding by Esso Production Malaysia, Incorporated. This paper documents the collection and analysis of data for selection of an optimum waterflood pattern. Included will be discussions on parameters that affect short and long term water injectivity, extensive use of numerical models to compare alternate waterflood patterns, on-site production/injectivity. tests to validate predictions and injectivity enhancement methods. With a going-in development plan for an inverted 7-spot waterflood pattern, the final optimum plan was assessed to be a combination of 5-spot and peripheral injection.
Infill Development in an Old Field
Authors: New K. T. C. , Slik P. , Tan B. C.
Published: December 2007

The Seria field, onshore Negara Brunei Darussalam on Che North Western coastline of Borneo, South East Asia, has been in production since 1930 and up to now some 34% of STOIIP has been produced by 760 wells.Ultimate Recovery, estimated from extrapolation of performance is 39% of STOIIP.

This paper outlines the approach followed in planning of infill drilling and presents recent experience for the Seria West (SW) block and three other blocks of field.

Infill drilling overall is expected to increase the ultimate recovery of the Seria field to 43% of STOIIP.
Enhanced Oil Recovery in Malaysia
Authors: Yassin A. A. M.
Published: December 2007

Whilst the incremental oil potentially recoverable by the application of enhanced oil recovery (EOR) processes can only be reliably estimated by a detailed study of each reservoir, in order to provide an early guide to the scope for EOR in Malaysia, a preliminary survey has been carried out. The approach in this preliminary survey was to develop a set of screening criteria for the various processes being developed and to use these criteria to identify possible candidate reservoirs. The potential for incremental oil recovery was then determined by applying factors obtained from the assessment studies referred to above or from published sources.

The review of EOR potential within Malaysia has suggested that only a small number of reservoirs are unsuitable for EOR and there is substantial scope for increasing the yield from known light oil and gas condensate reservoirs. The possible contribution that could be made by individual processes is fairly evenly distributed between polymer floods, surfactants, carbon dioxide and nitrogen or hydrocarbon gas.

The enforcement of strict conservation measures and depletion control had change the development strategy by integrating EOR into conventional method of production with an early implementation of EOR in order to maintain the viability of EOR projects.
Effectiveness of Enhanced Safety Management
Authors: Waterfall K. W.
Published: December 2007

Sarawak Shell Berhad (SSB) and Sabah Shell Petroleum Company (SSPC) are oil and gas exploration and production Companies working under a Production Sharing Contract (PSC) for PETRONAS. They operate or control the activities of Drilling-Rigs, Barges, vessels and approximately 100 Production Facilities offshore Sarawak and Sabah. Additionally they operate three onshore oil and gas terminals to treat the products prior to export.

Current production levels are in the order of 200,000 bbl/day of oil and 1000 million scf/day of gas. The Company employs some 3,000 Company personnel and approximately 2,600 contractor employees. With this spread of activities and this number of people there are many areas and operations being conducted on a daily basis which have the potential for accidents to occur. Whilst the programme and procedures stated in this paper are generally applicable throughout the Shell Group the references to Shell should be construed in this context as being relevant to SSB/SSPC activities only.

Shell has always been conscious of the need for improved safety and reduction of the risk of accidents throughout its operations and in 1984 it embarked on an intensive campaign of Enhanced Safety Management (ESM), which is modelled on the approach taken by Du Pont Organisation. Du Pont are the world renowned leaders in Safety Management and extensive use was made of their Safety Consultancy Division to establish Shell's ESM Programme. This programme has brought about a major improvement in Safety performance which is both sustainable and ongoing. Experience has shown that we can summarize the essentials of ESM to be.
Corporate Safety's Responsibilities and Duties to Petronas Offshore Facilities
Authors: Coleman H. R. , Salleh I. A. N.
Published: December 2007

In July 1986 PETRONAS approved establishment of a Corporate Safety Group with responsibilities for:

Initiating development of safety policies, procedures and guidelines. Implementing and monitoring same. Acting as official spokesman and liaison with Public and Third Parties.

Corporate Safety's area of responsibility is total. That is, safety must begin with design at the conceptual stage, including: developing design specifications and standards, participation in construction and in acceptance inspections, in operations by participating in the development of operating procedures for personnel safety and in the development of guidelines on safety matters related to Inspection and Maintenance. This paper will highlight the areas of Corporate Safety's involvement and support them with appropriate and logical reasons.
Development Planning of the F6 Gas Field in Central Luconia, Offshore Sarawak, Malaysia
Authors: Wee P. Y. , Liew S. L.
Published: December 2007

Development of the Central Luconia gas fields, located offshore Sarawak, started in 1982. To date three gas fields have been developed, Ell, F23 and the third and largest gas field, F6, which came on stream in January 1987. The daily production rate averages some 1000 MMscf/d.

The gas is delivered via a single 36" trunkline from Ell to the Malaysian LNG liquefaction plant for the manufacture of LNG at approximately 6 million tonnes per year for a period of 20 years. Gas is also distributed to the ASEAN Bintulu Fertilisation plant for the production of urea and ammonia, and to Sarawak Electricity Supply Corporation for power generation.

This paper describes the 3D simulation study that has been carried out for the F6 field which forms the basis for the development planning of the field. The plan proposed a total of ten producer and one observation well to be drilled from the drilling platform F6DP-A located near the crestal part of the field.

Despite the large reservoir areal extent of about 168 km2, it is expected that the field can be adequately drained from a single platform with ten producers.

The main uncertainties which may affect the field performance are the transmissibility of a tight argillaceous layer which may separate the gas bearing part of the field into two zones and the possibility of water drive. The likely impact of these uncertainties on the development plan and gas recovery has been addressed in the simulation study.

Taking the above uncertainties into consideration, recovery factors are estimated to be between 61% and 75%.
Jerneh Gas Field Development Planning
Authors: Thambydurai R. , Mustapha A. F. , Mueller K. H. , Dixon M. R.
Published: December 2007

This paper is a review of the field development plan for the Jerneh gas field, located offshore east of Peninsular Malaysia. The major design steps in the development process are discussed which include gathering of required geological and reservoir data from delineation wells and subsequent studies to evaluate reservoir performance, production and processing facilities. The result of these studies is a development plan which incorporates forty wells and two producing platforms.
Condensate Production Optimization in the Arun Gas Field
Authors: Risan R. M. , Abdullah S. , Hidayat Z.
Published: December 2007

In the Arun Field, Mobil Oil Indonesia Inc. (MOI) has implemented a condensate production optimization program on its Supervisory Control and Data Acquisition (SCADA) system. This program has been proven successful in improving stabilized condensate production by up to 3% or 3200 BPD at 2,270 MMSCF daily average separator gas flowrate.
The Variable-Rate Reservoir Limits Testing of Gas Wells
Authors: Blasingame T. A. , Lee W. J.
Published: December 2007

This paper presents a new method of estimating drainage area size and shape from production data (bottomhole pressures and flowrates) for gas wells. This method is rigorously based on theory presented earlier for the slightly compressible liquid case and requires a computer program to iterate on gas-in-place until the gas flow and material balance equations are satisfied.

The component equations and analysis technique are strictly applicable only after the initial pressure transient has reached the outer boundary. The gas flow equation that we present is an approximation for variable-rate, post-transient flow, but it has provided excellent results for all of the cases investigated. These results imply, as was also noted for the liquid case, that as long as the changes in flowrate do not dominate the influence of the outer boundary, this method should give acceptable results. Currently, this method is only derived for single-phase gas flow and does not consider the effects of geopressured gas reservoirs or non-darcy flow.
Nitrogen as a Low-Cost Replacement for Natural Gas Reinjection Offshore
Authors: Hanssen J. E.
Published: December 2007

As part of R&D efforts to evaluate nitrogen for pressure maintenance and EOR offshore Northern Europe, nitrogen miscibility with selected reservoir fluids as well as its diffusion properties have been investigated and compared to those of natural gas. Custom-built equipment includes slim-tube and cell-to-cell miscibility apparatus and a diffusion apparatus, all operating at typical reservoir conditions. Measured minimum miscibility pressures (MMP's) range from 32 to 55 MPa [4600 to 8000 psi]. With near-critical volatile oils from one reservoir, both nitrogen and methane were found to develop miscibility at saturation pressure. This apparently is the first such case known for nitrogen, and the lowest MMP value reported for nitrogen with a North Sea fluid. For another North Sea reservoir fluid, MMP was found to depend strongly on the amount of intermediates in the oil, and a significantly higher MMP measured for nitrogen than for methane. The new data were used to improve a previous MMP correlation for vaporizing gas drives. Predictions by this correlation indicate possible nitrogen miscibility with several North Sea reservoir fluids. Hitherto unavailable diffusivity measurements for the nitrogen-methane binary have been performed at reservoir conditions. Results indicate that serious errors in diffusivity may be introduced if lower-pressure data are used to extrapolate to reservoir conditions.

To complement the experimental work, a critical review of previous onshore nitrogen field application and various offshore process suggestions has been performed, in the perspective of nitrogen replacing produced-gas reinjection.
Use of Boundary Element Methods for Stochastic Optimisation of Gas Field Deliverability
Authors: Wadsley A. W. , Ferguson W. I.
Published: December 2007

Optimum gas delivery contracts are those which maximise gas production whilst minimising penalties caused by insufficient well capacity to meet contracted demand. The method of stochastic simulation is described for predicting seasonal and daily gas demand together with techniques derived from the boundary element method for the modelling of reservoir deliverability performance. These two methodolgies are combined to give a robust procedure for the nomination of contractual gas delivery quantities.
Breakdown Procedures Designed to Minimize Naturally Fractured Reservoir Damage
Authors: Branagan P. T. , Wilmer R. H.
Published: December 2007

Damage to natural fractures have been found to occur as a result of conventional completion techniques previously employed at the DOE Multiwell Experimental (MWX) Site. In an attempt to understand some of the damage mechanisms and find mitigating techniques that could be practically employed, a series of rather unconventional completion procedures were performed. These procedures were designed to utilize gases rather than aqueous-based fluids during the perforating and breakdown/ microfracturing process and were performed in several differing reservoirs. Previous tests at the MWX underscored the impairment to natural fracture flow capacity that resulted from liquid invasion during perforating, breakdowns or large scale stimulation. Thus, the use of gases during the initial connection into the naturally fractured reservoirs at the MWX was considered a natural starting point.

The completion techniques that were tested and that will be discussed employed nitrogen, N2, during dry hole perforating; as a fracturing fluid during simultaneous perforating and fracturing; and in an impulse remedial treatment. A test of a tailored pulse explosive technique provided useful operational information but inadequate wellbore preparation compromised an assessment of its effectiveness to create a multiple fracture set. The application of these unconventional techniques provided a very useful and unique set of test data and proved to be sufficiently effective in permitting the engineers to acquire positive pressure interference data during a subsequent well test.
Pre-Frac Interference Testing of a Naturally Fractured, Tight Fluvial Reservoir
Authors: Branagan P. T. , Lee S. J. , Cipolla C. L , Wilmer R. H.
Published: December 2007

The data, analysis and simulation resulting from a three-well interference test performed in a tight, lenticular naturally fractured reservoir at the Department of Energy (DOE) Multiwell Experimental (MWX) site, near Rifle, Colorado,1 will be discussed. The test data, that includes bottomhole pressure measurements from a production well and two closely spaced observation wells, provides considerable evidence that reservoir gas production was dominated by flow through a layered, anisotropic naturally fractured system. The interference testing consisted of almost two months of continuous data acquisition that included the introduction of several pressure pulses from the production well and the subsequent observation of those reservoir pressure transients at the remote well locations.

A series of novel completion schemes using high pressure nitrogen gas and explosive fracturing were employed in the completion process of all three wells. The primary intent was to eliminate foreign liquids from entering the reservoir fracture system following perforation in order to minimize external intervention in the natural production process.

When wellbore storage effects were considered to negatively impact the data set, bottomhole shut-in tools were employed and virtually eliminated storage volume. Both observation wells made use of these shut-in tools throughout the entire test yielding an unobstructed pressure interference data set.
Infill Drilling Using Horizontal Wells: A Field Development Strategy for Tight Fractured Formations
Authors: Mercer J. C. , Pratt H. R. , Yost A. B.
Published: December 2007

Gas production for a 10-year period was simulated for 16 vertical shot wells located in a 2,066-acre (8.36 × 106m2) area containing seven active vertical wells. The performance of several horizontal wells was simulated and the results were compared with that of the 16 vertical wells. Finally, the horizontal and vertical wells were compared to determine the best method for developing a virgin reservoir. As few as four unstimulated 2,000 ft (610 m) horizontal wells were found to produce 1.5 times as much gas as 16 vertical shot wells, and only two hydraulically fractured horizontal wells were needed to almost match the production of the four unstimulated horizontal wells. In a virgin reservoir, four unstimulated horizontal wells accounted for 95 percent of the total production from 23 vertical wells.
On the Performance of Noncontinuous Tight Gas Sands
Authors: Ubani E. A. , Ray R. M.
Published: December 2007

This paper discusses the development and application of a stochastic three-dimensional reservoir model for gas-water flow. The model treats the occurence of natural fractures and shales in the reservoir as random, and as such the discontinuities may be arbitrarily distributed among the reservoir grid blocks. A simple shale management scheme that does not require the formulation of a sand-shale permeability relationship 1s used. However, the developed model requires the estimation of effective flow properties for the fractured reservoir nodes. By this, we attempt to simulate the effective permeability measured by the slope of a fractured reservoir build-up curve. The model may be used to compute the reservoir performance of a fractured, lenticular sand gas reservoir as well as that of a conventional blanket sand. Results of demonstration problems based on published data on Paludal zones 3 and 4 of the Mesaverde formation 1n western Colorado suggest that the effects of sand lenticularlty may not be as marked as have previously been calculated by modifying sand thickness by sand lense factor.
Measurement of Longitudinal Dispersion Coefficients for Gas Flowing through Porous Media
Authors: Newberg M. A. , Foh S. E.
Published: December 2007

The Institute of Gas Technology's Sustaining Membershp Program is currently sponsoring research to investigate the use of inert base gas for natural gas storage fields. As part of that program, an apparatus was constructed in which to measure longitudinal dispersion of gases flowing through porous media. Whole core samples from several underground storage reservoirs were confined in a Hassler type coreholder. Two different gases (methane and nitrogen) were successively flowed through the core and the effluent concentration profile was recorded. Superficial pore velocities varied from 0.25 to 3.5 ft/hr [0.02 − 0.3 mm/s], and pore pressures were in the range of 500 − 1000 psi [3450 − 6890 kPa]. A single parameter diffusion-type equation was used to correlate experimental results. This model is used to generate longitudinal dispersion coefficients and "scale of dispersion" (dispersion coefficient divided by velocity).

The rate and degree of mixing of two gases in porous media seems to be predominantly controlled by three factors: the porous media itself, the viscosity ratio of the two gases, and the superficial pore velocity of the gases. Specifically: Mixing parameters were found to vary widely with different porous media, but do not see to be directly related to permeability, porosity, or tortuosity.In most cases, the values of dispersion coefficient and mixing length for an unfavorable viscosity ratio were greater than those for the favorable case. The magnitude of the difference between the two cases varies with different porous media.Dispersion coefficient increases with increasing velocity. This dependence may be linear for favorable viscosity ratios and some porous media. However, it is often not linear and needs to be measured for each porous media and set of gases.
Gas Research Institute Underground Gas Storage Research Program: An Overview
Authors: Shikari Yusuf A.
Published: December 2007

The Gas Research Institute (GRI) is currently involved in the development of concepts aimed at an enhancement of natural gas service to the consumer. In order to maintain the attractiveness of the gas options to industrial consumers, and to reinforce the "value-in-use" of natural gas to residential as well as commercial customers, it is essential to develop efficient, economical, and safe means of reducing the "cost-of-service", including that of natural gas storage in underground formations. Specifically, research and development (R&D) is needed to explore ways to better utilize existing storage fields and also to develop new storage facilities at minimum cost.

GRI is currently examining the feasibility of using foam in underground gas storage fields as a mobility control agent to reduce gas migration. Research is also being conducted to establish economic viability of substituting less-costly inert gas(es) for a portion of the base gas, to understand the gas-gas phase mixing behavior in gas storage fields via laboratory experiments and reservoir modeling, and to develop cost-effective gas separation processes using membranes.

This paper provides an overview of the GRI's Gas Storage R&D Program and highlights key results achieved to-date for selected research projects.
Subsurface Pressures and the Fracturing Gradient in Hydraulic Fracturing of Subsurface Formations
Authors: Luchetta John
Published: December 2007

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

This paper was prepared for the SPE Rocky Mountain Regional Meeting to be held in Casper, Wyo., May 22–23, 1967. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copies. The abstract should contain conspicuous acknowledgement of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.

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

Hydraulic fracturing calculations often employ fracturing treating gradients based on the total treating pressure applied at the sand face. Data presented in this paper indicate that more accurate predictions of fracturing pressures and fracture orientation result when reservoir pressure is considered. By this means, the fracturing gradient is reduced to a property of the rock only and more consistent values over wider ranges are prevalent.

Also, it is observed that values for vertical fracturing gradients very closely approximate values for subsurface horizontal stress as predicted by Hook's law.

Introduction

Analysis of pressures in large bodies of water follows straightforward laws of hydraulics whereby the pressure exerted at any particular depth is equal in all directions. In contrast, the pressures at depth in a sedimentary basin may be different in all directions. This difference in pressure greatly influences the choice of engineering techniques and design of hydraulic fracturing operations [see Figs. 5 through 7].

The force resisting formation parting has been represented by the sum of the instantaneous shut-in pressure and the hydrostatic head of fluid above the formation.

Application of this relation to field problems has been less than satisfactory in many instances because recent data are not available and it is often difficult to predict fracturing characteristics.

The purpose of this study is to propose an innovation to this concept that will give more accurate results and better describe the mechanism of the fracture gradient.

Discussion

As demonstrated by Hubbert and Willis, propagation of fractures in rock formations under hydraulic influence conforms to definite laws of mechanics and strength of materials as follows.

If the fluid pressure is applied locally within rocks and increased until fracturing of the rocks occurs, the plane along which fracturing will first occur is perpendicular to the least principle stress.
The Use of Inert Base Gas in Underground Natural Gas Storage
Authors: Misra B. R. , Foh S. E. , Shikari Y. A. , Berry R. M. , Labaune F.
Published: December 2007

The use of less expensive inert gas to substitute all or part of the base gas requirements in underground natural gas storage fields is a promising technology that has been successfully field tested in France. This paper discusses geological, reservoir, and operational factors that need to be considered in selecting an underground storage field for inert gas use. A storage field in the U.S. has been selected to illustrate detailed data collection and analysis that will lead to formulation of a plan to inject inert gas and predict long term field performance using reservoir models.

High base gas fraction, the presence of closed structure or an isolated area away from the injection/withdrawal wells, absence of large scale heterogeneity, and availability of adequate data for reservoir modeling are favorable features that would make a field an attractive candidate for inert gas use. The degree to which natural and inert gases will mix during the storage field operations can be predicted with the help of reservoir simulators now available.
Natural Gas: An Emerging Fuel in Indian Energy Scene
Authors: Mittal A. K. , Gupta A. K. , Goyal K. L.
Published: December 2007

The natural gas industry is a relatively new entrant in the Indian energy sector, it is on the verge of making significant contribution to the Indian economy and is expected to significantly contribute to reduce Gross Domestic Product - energy elasticity coefficient.

The seven fold increase in natural gas reserves during last twelve years have generated an optimism for future gas discoveries in Indian sedimentary basins. The natural gas production is expected to increase nearly five folds by the turn of century from the present level of eight billion cubic meter per annum. In this paper, an attempt has been made to determine an appropriate pattern for optimal utilisation of these large potentials of natural gas resources.

Presently, the priority use of gas is considered as feedstock in fertiliser sector. The relative scarcity of commercial fuels coupled with the burgeoning energy demand have paved the way for natural gas utilisation in other sectors. Systematic analysis has been carried out to determine the competitiveness of natural gas vis-a-vis other fuels/feedstocks in different sectors, taking into account, their historical growth trend.

The analysis indicate about eight fold increase in the deficit of power by the turn of the century, which can be economically and efficiently narrowed by the gas based power plants. The major portion of petroleum demand in transport and domestic sectors, presently met by import of middle distillates, may be substantially supplemented by natural gas, in future. Case studies for fuel replacement by gas, in these sectors, have also been discussed.

The integrated national development is expostulated by the development, distribution and diversification of natural gas through a ‘National Gas Grid’.
Gas Energy Supply Outlook: 1987–2010
Authors: Kalisch R. B.
Published: December 2007

Natural gas supplies are expected to be adequate to meet current consumption levels under all likely gas price scenarios throughout the period 1987-2010. At a maximum, potential supply capability could increase to 30% over peak U.S. consumption levels experienced in the early 1970s.

These gas supply estimates include the domestic lower-48 sources which consist of conventional gas production, gas from tight formations, coal seam gas and gas from co- production of gas and brine. These potential supply capability estimates have been developed without regard to specific gas demand constraints.
Acid Gas Treating at the Arun NGL Plant and Its Modifications
Authors: Purwonohadi P. , Soeryanto J.
Published: December 2007

At PT Arun, there are six LNG trains, each with its own treating system. The acid gas treating unit is the front end process of each LNG train, which reduces the CO2 content of the feed gas from 14.85 volume % to less than 0.05 volume % and the H2S from 80 ppm to less than 5.0 ppm by volume. Each treating unit was originally designed to process 314,359 Nm3/h of sour feed gas by using a proprietary Benfield Hi-Pure process.

In late 1979, a study was conducted by Bechtel Inc. to improve the treater capacity and reliability. At that time, modifications were made to the packing, exchangers, and piping, the capacity was improved from it's original design.

In 1983-84, a debottlenecking study was conducted to improve the train LNG capacity and concluded that both the carbonate and amine absorbers were a bottleneck. It was determined that the limitation in the unit was due to poor liquid distribution in the tower packing. The absorber liquid distributors were changed from a "V-Notch" to an "Orifice Riser" type, improving the treating capacity approximately 22% to 28%.

Presently, a new improved liquid distribution system has been installed in one of the the train's carbonate regenerator. This improved the regenerator efficiency from 170 to 190 SCF CO2/LB mole steam. We are now proposing to install this new type of distributor in the remaining five trains in the next scheduled shutdowns (1988-89). A continuing effort to improve the plant treating capacity is still on going at the Arun NGL plant.
Hydraulic Fracturing of a Horizontal Well in a Naturally Fractured Reservoir: Gas Study for Multiple Fracture Design
Authors: Yost A. B. , Overbey W. K. , Wilkins D. A. , Locke C. D.
Published: December 2007

Stimulation of a naturally-fractured, low permeability, low-pressure 2000-foot horizontal well in a low permeability reservoir and in-situ stress environment requires careful stimulation fluid design to minimize the capillary retention of treatment fluids. Therefore, a systematic approach to stimulation design using N2, CO2, and N2-foam was used to select one which is most efficient. Stimulation modeling was used to evaluate fracture geometry with particular concern for the minimum pressure rise above parting pressure required for height growth during frac fluid injection. Up to seven zones along the horizontal wellbore are available for stimulation. Each zone was ranked and pre-frac tested to establish pre-frac permeabilities. A N2 and N2-foam data frac was performed in one zone to establish leakoff characteristics. Subsequently, N2, CO2, and N2-foam treatments were performed on a 400-foot zone to evaluate the effectiveness of CO2 versus N2 frac fluids. Both the data frac and subsequent stimulations were evaluated in the two least productive intervals in order to use the preferred fluids in the best zones in the reservoir. The post-treatment decline curves for N2 and CO2 indicate a CO2-based fluid treatment should be performed in the most productive interval to achieve maximum success. Results of the stimulation conducted are presented along with discussion of improvement ratios and potential utility to other horizontal drilling projects.
Operating Problems in the Hanlan Swan Hills Gas Field
Authors: King W. J.
Published: December 2007

The design, construction, startup, and operating phases of major projects involve several different people. Operating problems encountered subsequent to initial startup are not always communicated to designers. This can result in design errors being repeated and costly modifications being required after initial construction.

The intent of this paper is to review several operating problems encountered in producing the Hanlan Swan Hills gas field since startup in March 1983. These problems and the resulting recommendations should be considered in the design and operation of future deep sour gas systems.
Assessment of Gas Production Potential From Coalbeds and Adjacent Strata.
Authors: Layne A. W. , Siriwardane H. J. , Byrer C. W.
Published: December 2007

Pipeline quality gas production from the highly fractured methane-bearing strata above longwall coal mine panels is predicted to be many times that of the gas-in-place estimate for the minable coalbed. This production is thought to come from relatively shallow gas-bearing coals, organic shales, and sandstones. In the mining process, permeability of shallower strata is increased significantly because of the fractured zone generated during longwall mining activity and, hence, gas could be produced at volumes many times that of an average conventional gas well. This paper assesses the potential production and the influence of well spacing on the drainage of gas from the strata above mining operations in southern Appalachia. In this assessment, gas reserves were quantified for a typical failure zone, formation gas content, and geologic cross section present in the Appalachian Basin. A finite element method was used to determine the size and shape of the affected stratigraphic areas for which gas contents were estimated (based on prior knowledge). A two-phase reservoir model was used to compute increased production rates from methane wells that penetrate the multiple strata and coalbed. Production data from actual wells above a longwall panel were history matched to characterize flow mechanisms and reservoir properties. These properties were then evaluated in parametric studies to determine the influence of well location on gas production. Results indicate that cumulative gas production can be increased by placing wells farther apart than 1,000 ft (304.8 m). The model appears to make reasonable predictions of the size of the multi-reservoir area in complex geologic conditions. The study considered the influence of an advancing mine face on gas production. Thus, the methodology presented in this paper is applicable to the location of gas wells in highly fractured reservoirs to optimize long-term gas production.
On the Quality of Data From Standard Gas-Condensate PVT Experiments
Authors: Drohm J. K. , Trengove R. D. , Goldthorpe W. H.
Published: December 2007

From an analysis of the constant volume depletion experiments performed on 80 gas-condensates, it is concluded that serious problems exist in the detection of the actual volume of retrograde liquid in the PVT cell. The measured liquid volume is usually only a fraction of that required to give realistic liquid densities. The frequently observed concave shape of the retrograde liquid saturation curve close to the dew point is not real and is the result of experimental error. It is recommended that the data quality be improved by directly measuring the retrograde liquid density because it provides an excellent control over the liquid saturation, especially when this saturation is low.

The properties of the fluid initially in the PVT cell are normally determined mathematically. However, this often only approximates the true properties and deviations can have consequenses for the derived liquid properties. The direct measurement of the composition and properties can easily solve this problem and is therefore strongly recommended.

The analysis of the experiments leads to the following statements for constant volume depletion experiments liquid densities are monotonically decreasing with pressureBom and Rsm are both monotonically increasing with pressure.

Here Bom is defined as the inverted partial density of the C5+ component fraction in the liquid, while Rsm is the mass ratio of the effraction over the C5+ mass fraction.
Microwave Technique for Phase Behavior Studies of Petroleum and Natural Gas Mixtures
Authors: Rogers W. J. , Eubank P. T. , Hall K. R. , Holste J. C.
Published: December 2007

We have developed a new technique that utilizes microwave energy to study the phase behavior of mixtures at the extreme temperatures and pressures encountered in petroleum and natural gas reservoirs. Our technique measures shifts in a static microwave energy field caused by changes in sample properties on a phase boundary. The appearance of a second phase produces detectable changes in the microwave resonant frequency and power. The new method does not involve inaccurate or unsafe procedures such as visual observation of samples, interpolation of isochoric slopes, or compositional analysis of samples drawn from the sample cell. Only small sample cell volumes (<10 cm3) are required.

The microwave technique is effective with all types of fluids, light and heavy, nonpolar and polar, inert and corrosive, and it performs well at extreme conditions of pressure and temperature. A magnetic mixing pump enables preparation of homogeneous mixtures of fluids within the apparatus at experimental conditions. Measurements can be made at constant volume or at constant temperature. At constant volume, the microwave technique can determine phase boundary temperatures to better than 0.1 K. Pressure accuracy depends on the method of measurement. Results for phase boundary determinations of acid-gas mixtures with small amounts of heavy oils at high pressures and temperatures are presented.
Performance Data Through 1987 of the Isenhour Unit, Sublette County, Wyoming, Polymer-Augmented Alkaline Flood
Authors: Doll T. E.
Published: December 2007

The Almy sands in Sublette County, Wyoming have some 19 years of volumetric sweep improvement history. In an effort to reduce residual oil saturation in the swept area, the first field-wide alkaline flood was initiated in September, 1980 at the Isenhour Unit.

Based on core testing, crude oil-alkaline agent screening determined that soda ash (Na2C03) and anionic polymer would be most beneficial in reducing interfacial tension (IFT) and mobilizing residual oil. Core flooding indicated that alkaline agent could be injected into the high clay content Almy sand. A significant decrease in oil saturation on a percent pore volume basis was predicted.

This paper details flood performance up to January 1, 1988. Injection is now 67.2% of the total pore volume. A cationic and anionic polyacrylamide spearhead preceded the addition of the alkaline agent. Anionic polyacrylamide followed for mobility control. The program utilized a tripolyphosphate-anionic polymer blend for long-term wettability control and alkaline slug stability. Fresh water injection continues this date. Recovery to-date is 26.4% of the 00IP. Oil production inclined at a rate of 20% per year since the start of the polymer augmented alkaline flood to 1985. Oil production then declined at approximately 35% per year until mid-1987 with the drilling of #15 for the southwestern expansion of the reservoir.
Improved Gas Migration Control in A New Oil Well Cement
Authors: Fery J. J. , Romieu J.
Published: December 2007

Problems created by the migration of gas in drilling and production cements are well-known today. Intensive testing on new laboratory equipment led to a recently developed system resulting in a cement which has excellent mechanical properties and is efficient against gas migration.

Two new products were combined to achieve this result: –a polymer able to produce a gummy substance when the cement sets, which forms a tight barrier in the cement,–a new type of binding material made of Portland class G HSR cement blended with blast furnace slag wich has high mechanical properties and very low porosity.

Their field applications in well cementations are as different as high temperature or shallow gas problems.

In this paper laboratory research on gas migration and on these new products as well as results of their application in the field are reviewed.
Evolution of Reservoir Simulation for a Large Carbonate Reservoir
Authors: Al-Dawas S. M. , Krishnamoorthy A. M.
Published: December 2007

Reservof-1 is a large carbonate reservoir that was discovered and developed in the 1940's. A brief description of the reservoir and major events of the field development are presented.

A 2D areal model was constructed for the reservoir in the 1970's. The use and the shortcomings of the model are discussed.

A 3D model was constructed for the reservoir in the 1980's. The justification for the construction is outlined. The utilization of the model is presented with some examples,

Reservoir-II underlies reservoir-I and both are in communication through fractures in the intervening formation. A model combining both of the reservoirs was constructed. The use of the model to investigate the effects of the communication, and depletion of reservoir-II is discussed.

For all the above models, a separate coarse grid 2D aquifer model is used to generate fluxes to simulate aquifer support. A recent software development (Locally Refined Grid) allowed the 3D fine grid model of reservoir-I to be embedded in the 2D aquifer model. The experience with the LRG model is discussed.

The computer resource requirements for all the above 4 models are displayed, showing increasing requirements with complexity. The concept of multiple model utilization is presented.

Conclusions based on model utilization, resource requirements and expectations, are presented.
Estimating Formation Permeability and Producibility in Oil-Based Mud Using the EPT
Authors: El Shafei I. , Zaki M. , Andreani M.
Published: December 2007

Most mathematical correlations to determine permeability consider porosity (Ø) and the irreducible water saturation (Swirr). Porosity is a function of the number of channels conducting fluid, while Swirr relates to the geometry of these channels - to their radii in particular. It has long been recognized that permeability is related to the grain size and compaction of a system, and to the channel path tortuosity. As the grain size increases, there is also an increase in pore radius and a corresponding decrease in surface area. This decrease in surface causes a decrease in the irreducible water value. Thus, changes in Swirr can be used as indirect measurements of grain size variations. Therefore, a value of Swirr is necessary in order to determine permeability from any of the standard mathematical correlations.

In an oil-bearing zone, Swirr can be determined from the deep resistivity measurement, Rt. However, to accomplish this, representative values of the porosity and saturation exponents (m and n) are needed. In water-bearing and transition zones, classical resistivity measurements cannot be used to determine Swirr.

The introduction of electromagnetic propagation measurements in the invaded zone has opened new avenues for determining Swirr in both oil and water-bearing formations. As the oil based mud invades the formation, the oil will displace the moveable water in the invaded zone leaving only the irreducible water. These electromagnetic measurements also provide the additional advantage of eliminating the need for values of m and n.

This paper considers permeability evaluations made using the Electromagnetic Propagation Tool (EPT*) in oil based mud environments. The computed permeability values were used to estimate formation injectivity and producibility and to optimize the completion program, and were found to compare very favourably with test and production data. This technique was used successfully to identify high permeability streaks and impervious formation layers.
Stimulation of Two Adjacent Dolomite and Sandstone Layers in the Sahmah Field
Authors: Al Bussaidi S. , Champetier J-L. , Lassus-Dessus J.
Published: December 2007

After production from the lower HAUSHI reservoir of the SAHMAH field (SULTANATE OF OMAN) to its high water cut limits, wells were completed In the upper HAUSHI. The proven reserves of the upper HAUSHI reservoir are shared between two adjacent layers, a dolomitic drain overlain by a sandstone level. Added difficulty is that the reservoir is deep (3250 m, 10700 ft), hot (120 C, 250°F) and partially depleted.

The optimization of the stimulation design and its Implementation on the field are crucial in this tight oil bearing formation. Procedures and field results of a typical design are presented. Formation rock properties of the pay zone and adjoining barriers were determined from core samples and sonic log analysis. The fluid and proppant selection were based on laboratory experiments. A 2D-frac simulator was used to optimize the size of both acid and propping treatments.

First, an acid treatment was conducted on the dolomite. Significant rig time was saved by using a new method of temporarily sealing the dolomite zone. Next, a minifrac job was performed on the sandstone.

The results of the minifrac were used as a calibration for the design of the final frac job and to adjust the propping treatment. After hydraulic fracturing, economic production rates were obtained from the upper HAUSHI.

Chief technical contributions: Detailed description of a successful hydraulic stimulation and field results for a reservoir having adjacent dolomite and sandstone layers.Use of mlnlfrac as a decision tool to evaluate the feasibility of the propping treatment to be used on the sandstone level.Optimization of diverting techniques to save rig time.