bluuebunny/crossref_metadata_2025 huggingface dataset:
Grand Canyon Directional Drilling and Waterline Project
Authors: Lattimore G. M. , Carden R. S. , Shursen Grace , Fischer T.
Published: December 2007

A high inclination directional drill hole was designed as a conduit to carry a fresh water pipeline from an intermediate pump station to the south rim of the Grand Canyon. This use of directional drilling technology was judged superior to an external pipeline for reasons of worker safety, aesthetics, pipeline protection and costs. The hole was designed to meet Park Service criteria: sufficient diameter to contain 8″ water line and exit point accessability.

The hole was drilled to a maximum inclination of 71°. True vertical depth was 2800 ft (855 m) and horizontal displacement was 3800 ft (1160 m). Measured depth along the wellbore was 5075 ft. (1555 m).

A "build-and-hold" pattern was employed from below surface casing, using positive displacement motors, tricone bits and "build" type rotary drilling assemblies. An air and mist circulating system was employed. Modifications of mud drilling equipment were made for air service.

Primary directional measurement was performed with magnetic singleshot instruments. Three confirmation/comparrson gyro runs were made. The visibility and accessability of the exit point afforded an opportunity to compare downhole surveying techniques with surface systems of known and verifiable accuracy.

Drilling problems encountered included: loss of circulation, fractures, solution cavities, severe torque and drag, severe drill string damage, hole cleaning, and sealing and cementing of an open-ended annulus. Solutions considered and implemented are discussed.
Rheological Properties of Foam Fracturing Fluids Under Downhole Conditions
Authors: Cawiezel K. E. , Niles T. D.
Published: December 2007

Foams are complex mixtures of gas and liquid whose rheological properties are largely influenced by foam quality, temperature, pressure and shear rates. A comprehensive study of the effects of these variables on the rheological properties of foams was conducted as a first step to understanding, defining and predicting the rheological properties of foam fracturing fluids.

Rheological properties of nitrogen/water/surfactant foams and gelled foam fluids were evaluated using a recently developed foam rheology simulator. The simulator is capable of exposing foam fluids to temperatures of 400°F (204°C), pressures to 10,000 psi (68.9 pKa) and shear rates to 100,000 sec−1. Results indicate that the rheological behavior of foam fluid is primarily that of a yield-pseudoplastic fluid and can best be described by a Herschel-Bulkley model. As foam quality increases so does its apparent viscosity and it becomes increasingly more pseudoplastic. Foams exhibit yield points whose dependency on quality is very similar to that of apparent viscosity. Temperature has little affect on the foam flow behavior but significantly affects its viscosity. The apparent viscosity of the foam decreases as the temperature of the foam increases. Pressure increases cause an increase in the apparent viscosity of foam systems, while an increased shear rate reduces the apparent viscosity. Effects of foam quality, temperature, pressure and shear rate on gelled foam fluids follow the same trends as those found for simple nitrogen foam fluids. Differences in bubble size and bubble size distribution effect changes in foam quality, etc., and give physical explanations for the observed changes in the rheological behavior of foam fluids.

The complexity of foam systems and their sensitivity to external conditions require that foam system properties be closely controlled and monitored in field use to optimize the frictional pressure required to utilize foam fracturing fluids.
Production Improvement Through Identification of Conductive Natural Fractures Utilizing Multiple Radioactive Isotope Technology
Authors: Lopus T. A. , Seifert D. J. , Schein G. W.
Published: December 2007

Recently developed technology with a high-rate, high-volume stimulation technique has been utilized to identify naturally conductive fractures in the Austin Chalk. Past completion theories suggested that conventional two wing vertical hydraulic fractures could be achieved. However, the fracture gradient of the Austin Chalk matrix is approximately 1.0 psi per foot. Experience has shown that treatment pressures equate to a conventional fracture – gradient of .50 to .68 psi per foot. The use of gamma ray spectroscopy devices and multiple radioactive isotopes has helped verify that hydraulic fracturing treatments are limited to the naturally existing fractures.

A recompletion program has been developed utilizing the following procedure:

A base Compensated Spectral Natural Gamma Ray (CSNG)* log is run. The well is perforated utilizing original open hole logs and the CSNG to identify natural fractures and previously produced intervals. A high-rate, high-volume stimulation treatment intended to remove by dissolution or abrasion secondary mineral deposits in the natural fracture system is performed. Within the stimulation treatment, diverters are incorporated which are traced using multiple radioactive isotopes. A post treatment CSNG Log is run and the TracerScan* technique, which resolves the different isotopes, is used to identify zones of fluid entry and subsequent diversion.

An increase in production has been observed using this technique. A description of the stimulation process, multiple isotope placement and TracerScan technique along with log examples and production history are presented.
A Method for Predicting Horizontal Well Performance in SolutionGas-Drive Reservoirs
Authors: Plahn S. V. , Startzman R. A. , Wattenbarger R. A.
Published: December 2007

A new set of type curves are presented which can be used to forecast oil production from horizontal wells producing at their maximum rate (with constant hottomhole pressure) from homogeneous, isotropic, solution-gas drive reservoirs.

The type curves were developed by correlating the results of 48 reservoir simulation runs. The input i data used in the simulation runs was chosen so it would encompass a wide range of PVT properties, relative permeability characteristics, rock properties, and well dimensions.

A new dimensionless variable is proposed which normalizes the reservoir simulation results. It appears, therefore, that production forecasts can be made without the use of a reservoir simulator. The type curves should be used primarily to screen can didate reservoirs for horizontal drilling possibilities.
Coupling and Attenuation: A New Measurement Pair in Cement Bond Logging
Authors: Leslie H. D. , de Selliers J. , Pittman D. J.
Published: December 2007

Acoustical coupling is proposed as a new measurement to complement the attenuation rate measurement now available with multispacing cement bond logging tools. Coupling responds principally to the mechanical impedance and distribution of material outside the casing, but is largely insensitive to bonding. Estimates of cement strength may be obtained even in the presence of microannulus.
Viscoelasticity of Crosslinked Fracturing Fluids and Proppant Transport
Authors: Acharya A.
Published: December 2007

In hydraulic fracturing treatments, the success of the treatment strongly depends on the proper placement of the proppant particles in the fracture. By proper placement, one means the packing of the fracture to achieve maximum conductivity of gas/oil through the fracture into the wellbore. The placement of the proppants along the fracture is based on design equations where sand transport velocity is related to the rheological parameters of the fracturing fluid and characteristics of the proppant particle such as size and density. The current design equations consider viscous parameters such as K' and n' of power-law model. In practice, however, there are numerous cross-linked fracturing fluids which are not just viscous, but visco-elastic in nature. At present, there are no design equations for proppant transport that can be incorporated into a hydraulic fracturing program which takes into account linear and non-linear viscoelasticity of cross-linked fluids.

The purpose of this paper is three fold. The first part of the paper describes the theoretical transport equations that take into account the elasticity of the fluid in predicting proppant settling rate in the fracture. The second part of the paper presents the experimental data of commonly used fracturing fluids (titanate and borate cross-linked). The rheology data includes both viscous and elastic parameter measurements using Rheometrics Pressure Rheometer and Rheometrics Mechanical Spectrometer. This data shows some important differences between borate cross-linked gels and titanate cross-linked gels. The third part of the paper presents experimental data of proppant settling rates in various fracturing fluids and how these can be correlated with rheological parameters that were obtained in this work. The difference in rheology between borate and titanate gels was correlated with the difference in settling rates of proppants in these two gels. Based on the theoretical and experimental work presented in this paper, it is concluded that the model for proppant placement in a hydraulic fracture should include: (i) proppant characteristics, (ii) viscous rheological parameters (K' and n'), (iii) elastic parameters (complex dynamic viscosity) from linear viscoelastic constitutive equation, and (iv) normal stress difference from non-linear viscoelastic constitutive equation. The influence of cross-linked polymer gel network structure on proppant transport is also discussed.
Understanding Formation Damage Processes: An Essential Ingredient for Improved Measurement and Interpretation of Relative Permeability Data
Authors: Amaefule Jude O. , Ajufo A. , Peterson E. , Durst K.
Published: December 2007

Anomalous trends have been observed in laboratory-derived relative permeability data especially in rock samples that contain mobile (siliceous/micaceous/ kaolinitic) fines and/or water sensitive clays. Water-oil relative permeability data determined for such rocks by the unsteady-state technique have at times exhibited the following characteristics:Non-monotonic trends with saturationSlightly S-shaped relative water permeability with a ‘bend-over’ at high water saturationsRebound in relative water permeability at residual oil saturation with reversal in flow direction

These characteristics are indicative of adverse physicochemical interactions between the flowing phases and the rock, which invalidate the relative permeability concept.

This paper presents the results of laboratory studies conducted to elucidate the role of formation damage processes in the determination of relative permeability data. Experimental data generated on rocks with fine particulates, indicate that mechanically induced damage can occur if the displacing fluid velocity, increased to overcome capillary end effect, exceeds the critical velocity for mobilization of resident mineral fines. Chemically induced damage was found to accompany the mechanical damage if the injected brine was not in ionic equilibrium with the rock.

Most friable samples containing micas, feldspars and illite/kaolinite, which have potassium ions in their interlayer sites, were damaged by the flow of sodium and/or calcium chloride brines during brine permeability tests. Critical velocities for entrainment of fines were determined to be higher for KCl brines than for NaCl/CaCl2 brines in water-wet Berea samples.

Laboratory protocols which eliminate formation damage processes during relative permeability measurement have been developed and are presented in this paper. These include: (a) use of velocities less than critical for floods on butted cores with lengths sufficient to reduce capillary end effects, (b) addition of trace ions such as K+ ions in simulated formation brines, (c) equilibration of the fluids with the rock and the use of aged fluids for dynamic displacement. Unsteady-state imbibition tests performed on short core plugs at flowrates greater than critical for fines mobilization, are discouraged. Rather, low rate floods should be conducted and the data analyzed by numerical techniques which include the capillary pressure term in deriving relative permeability curves.
Effect of Clay Swelling and Fines Migration on Formation Permeability
Authors: Civan F. , Knapp R. M.
Published: December 2007

A phenomenological model for the estimation of porous formation permeability considering the effect of clay swelling and fines migration is presented.
Legal Duty to Market Natural Gas in a Declining Market
Authors: Dancy J. R. , Dancy V. A. , Taylor L. S.
Published: December 2007

Marked changes in the natural gas industry have occurred over the last few years. Much natural gas has been freed of comprehensive price controls under the Natural Gas Policy Act, and direct or spot sales have become commonplace. The price of "old gas" has been devintaged under FERC Order 451, and FERC Order 436 has encouraged pipelines to transport natural gas on an open access basis to end users or local distribution companies.

In addition to these marked regulatory changes, the overdeliverability surplus and the decline in crude oil prices has severely depressed the market price of natural gas. Wellhead values in producer states have fallen by as much as one-third over the last two years. The following chart of natural gas wellhead values in Oklahoma illustrates the severity of the price decline.1/

Even with the price decline it should be noted that in many producing states gas production is at or near all-time record levels. Early exploration and development efforts focused on oil production because of the limited markets and low prices for natural gas, and only recently has gas production become a highly valued commodity. For example in Oklahoma oil production peaked in 1927, however natural gas production in Oklahoma peaked in 1984, and has doubled since 1960. The total value of natural gas production has also recently peaked in most producing states.
Rate Acceleration and the Untimely Depletion of Petroleum Assets
Authors: Campbell J. M. , Campbell R. A.
Published: December 2007

The oil industry suffered hard times recently and faces the prospect of equally difficult times in the near future. Some of the problems arise from conditions beyond the control of an individual company, but others arise from the methods employed in the analysis and management of petroleum investments. Faced with pessimistic price forecasts at present and, given the limitations of the methodologies used to evaluate such projects, current investment decisions may be hastening the uneconomical waste of companies and nations resources. The cause of the inefficient, unprofitable production of such resources and ways to avoid the untimely depletion of our scarce resources are outlined in this paper. The problem is introduced first, limitations identified, and several correcting methods presented. Each is illustrated with one or more examples.
Operation of the Central Basin CO2 Pipeline System
Authors: McCollough D. E. , Stiles R. L.
Published: December 2007

The Central Basin Pipeline (CBPL) is a 178 mile carbon dioxide (CO2) pipeline system located in the Permian Basin area of West Texas, see Figure 1. It is a private contract carrier system which was commissioned in November, 1985 to provide CO2 transportation service for enhanced oil recovery (EOR) projects. The CBPL transports CO2 in dense phase. Accurate custody transfer of CO2 is accomplished through standard orifice meters in conjunction with state of the are mass measurement and computer equipment. Measurement and computer data, and control signals are transmitted to a control headquarters located in Odessa, Texas and Omaha, Nebraska via standard telephone lines. The coupling of traditional and high technology elements have been very successful in the CBPL System operation.
Oil Hedging Strategies Using Futures and Options: Applications for the State of Alaska
Authors: Lindahl M. , Venkatesh E. S.
Published: December 2007

The continued decline in the price of oil and increased uncertainty about future revenues have caused severe budgetary constraints for oil companies and for states dependent on oil revenue. Using the futures market to hedge against adverse price changes is becoming an important tool in the oil industry to establish future dollar income figures. An additional hedging tool, options on crude oil futures, began trading on an organized exchange in November, 1986. Like other options, they offer a means of buying insurance against a potential price decrease.

This paper describes the possibilities of risk reduction that are available through crude oil futures contracts and the new options on crude oil futures contracts, and examines the case for the state of Alaska. Basis risk, the key variable based cn the relationship between cash and futures prices, is calculated for Alaska North Slope oil and the results are interpreted to judge hedging strategies for Alaska. A variation of traditional hedging, called Exchange of Futures for Physicals (EFP), is also presented as an alternative hedging plan.
Heber Geothermal Field: Reservoir and Production Characteristics
Authors: Hoang V. T. , James E. D. , Epperson J. I.
Published: December 2007

Heber reservoir has a dual permeability structure which controls the movement of the thermal fluids in the geothermal system. The three key permeability elements of the Heber reservoir are: "capping" clays above 1800', a matrix permeability dominated region from 1800'–5500' in deltaic sandstones, and a fractured "feeder" zone in indurated sediments below 5500'. The fractures are created by NW trending strike slip faults and NE trending normal faults. The permeability structure of the reservoir was defined by logs, core analyses, temperature, transmissivity and lost circulation data. Initial production creates a sharp pressure decline in the center of the producing area that rapidly stabilizes. Long-term pressure decline is predicted to be low (less than 5%). Pressure is the main factor which limits the development of Heber reservoir. Temperature data and reservoir modeling indicate that additional production can be developed in the fault zones south of the current development.
Pressure Transient Analysis of Heterogeneous Naturally Fractured Reservoirs
Authors: Jalali Y. , Ershaghi I.
Published: December 2007

In naturally fractured reservoirs, the transition zone observed on semi-log plots of pressure data versus time exhibits slope characteristics that are often ignored by the analyst. This study shows that analysis of this segment can lead to the quantification of matrix heterogeneity and fracture intensity. A pressure transient model is developed to substantiate this concept. It is found that the transition zone slope characteristics cover a spectrum embracing, as special cases, double porosity and triple porosity response corresponding to both pseudo-steady state and unsteady state inter-porosity flow.
Frontal Advance Theory for Flow in Heterogeneous Porous Media
Authors: Pande K. K. , Ramey H. J. , Brigham W. E. , Orr F. M.
Published: December 2007

This paper concerns the application of frontal advance theory to displacement processes in heterogeneous porous media. The assumptions under which a generalized frontal advance equation can be used to describe a flow process in a heterogeneous porous medium are examined. Material balance equations are derived based on these assumptions, and the theory is illustrated by application to the Dykstra-Parsons model of flow in noncommunicating layers. We show that the resulting formulation can be used to forecast performance and to solve the inverse problem: the determination of a permeability distribution from displacement data. This approach can also be used to determine pseudorelative permeability curves appropriate to a one-dimensional description of a layered system. We also consider the use of pseudorelative permeabilities in simulation studies to represent the effects of reservoir heterogeneities with length scales smaller than a grid block. The dependence of process performance and pseudorelative permeabilities on scale is described.

Results show that frontal advance theory may be applied to flow in heterogeneous porous media for processes that exhibit linear characteristics. In such a process, a given saturation travels at a constant velocity through the porous medium. Displacement performance for the two-dimensional Dykstra-Parsons model is exactly duplicated using one-dimensional frontal advance theory for unit mobility ratio displacements. One-dimensional theory reproduces the qualitative performance of the two-dimensional model for nonunit mobility ratios, but exact quantitative agreement is not obtained, because the characteristics are nonlinear.

Pseudorelative permeabilities determined for a system of noncommunicating layers apply to any scale as long as the layer structure does not change with system length. However, for processes that are not purely convective, process performance varies with the scale of the displacement Thus, pseudorelative permeabilities obtained from flow processes that are not purely convective are only applicable to the scale at which the displacement data was measured.
Through-Casing Reservoir Evaluation Using Gamma Ray Spectroscopy
Authors: North R. J.
Published: December 2007

Induced gamma ray spectroscopy has proved to be a valuable tool for through-casing reservoir evaluations in California. The data have provided reliable fluid saturations and lithology information under a variety of conditions. This paper examines several applications of these measurements. Environmental considerations and logging limitations are discussed. The cased hole answers are compared with openhole logging measurements, core data, and production results.
Detection and Control of Hydraulic Fractures in Water Injection Wells
Authors: Holzhausen G. R. , Egan H. N.
Published: December 2007

High- and low-frequency pressure analysis, tiltmeter surveys and passive borehole seismic measurements comprise a powerful set of tools for detection and tracking of induced fractures in water disposal wells. Used singly or in combination, these methods provide the capability for continuous monitoring of subsurface fracture behavior during injection.
Use of Scrubber Waste as an Oxygen Scavenger in Thermal Water Plant Operations
Authors: Williams R. L. , Harris A.
Published: December 2007

For the past eighteen months, Santa Fe Energy has successfully used sodium sulfite from scrubber waste as an oxygen scavenger in a 15,000 BWPD water plant in the Midway-Sunset Field. In using scrubber effluent as an oxygen scavenger, Santa Fe Energy has realized a $600/day cost savings from a reduction in chemical purchases for sodium sulfite (oxygen scavenger), scrubber effluent disposal costs, and vacuum truck charges, and an improvement in steam generator feedwater quality.

Commercial soda ash (sodium carbonate Na2CO3) is used in the scrubbing process to remove combustion by-products during steam generation. Sulfur dioxide is the primary target of this scrubbing process, and is generated when fuel oil with high (1–2% sulfur) content is burned in the generators. The spent scrubber effluent contains between 2.3–5.5% sodium sulfite and sodium bisulfite, which can be used for oxygen scavenging in boiler feedwaters. Between 1 to 2 barrels of scrubber effluent per 1,000 bbls of water are required to remove the 4 ppm of oxygen found in Santa Fe Energy's purchased water supply and provide a 30 ppm sodium sulfite residual from the water plant.

Details concerning the equipment used, installation costs, trial test, subsequent operating parameters and cost savings are provided in the discussion. Similar systems are being installed in other Santa Fe Energy water plants in the valley. Use of scrubber liquor to trim oxygen scavenging chemical consumption in our produced water systems is under evaluation.
An Experimental Investigation of Gas-Bubble Breakup in Constricted Square Capillaries
Authors: Gauglitz P. A. , St. Laurent C. M. , Radke C. J.
Published: December 2007

Recent advances in enhanced oil recovery involve generating foam within underground porous media to displace the oil. We investigate experimentally the important snap-off mechanism of gas-bubble generation in constricted square capillaries. Sixteen mm movies record the snap-off of smaller bubbles from a larger bubble as it moves through the constriction. The time required for bubbles to snap off once they move past the constriction, and the length of the generated bubbles are obtained from viewing the movie frames. The bubble capillary number, μUT/σ, is varied from 10−5 to 5 (10−3) by adjusting the wetting fluid viscosity, μ, and the surface tension, σ, by the addition of aqueous surfactants to mixtures of glycerol and water, and by altering the bubble velocity, UT.

Results show that a dimensionless time to snap-off depends weakly on the capillary number, and that the generated bubble size increases almost linearly with increasing capillary number. Surfactants create dynamically immobile interfaces for surfactant solutions of 1 wt% sodium dodecyl benzene sulfonate (SDBS) and Chevron Chaser SD1000. Compared to the surfactant-free solutions, the time to breakup with surfactants increases by a factor of about three; generated bubble length increases by at most a factor of three.
Physical and Chemical Effects of an Oil Phase on the Propagation of Foam in Porous Media
Authors: Jensen J. A. , Friedmann F.
Published: December 2007

Laboratory experiments were performed to determine the effects of a residual oil phase to hot nitrogen flood on the propagation of surfactant foam in Berea sandstone rocks. Static phase behavior-type tests were performed in support of the displacement tests. In the static experiments, surfactant partitioning into the oil phase and thermal degradation losses were measured. The chemical and physical properties of the oil phase were varied by the employment of four crude oil and two synthetic oil samples. The chemical properties of the surfactant phase were varied by the employment of three different foaming sulfonate surfactants. Each oil was analyzed for composition and physical and interfacial properties were measured. The effect of the presence of an oil phase on foam propagation was found to be strongly surfactant-specific. Implications of the results on the mechanisms controlling oil production in reservoirs containing steam override zones and channels are discussed.
Salt Cements for Improved hydraulic Isolation and Reduced Gas Channeling
Authors: Lewis W. J. , Rang C. L.
Published: December 2007

Inflows of gas into the primary cement slurry column of wells in the Ten Section field of Kern County have severely damaged the cement integrity. An inexpensive cement slurry and process design has been implemented that minimizes gas flows into the cement and eliminates the need of expensive remedial squeeze work.
Transient Pressure Behavior of Multiple-Fractured Gas Wells
Authors: Choo Y. K. , Wu C. H.
Published: December 2007

Virtually all studies on transient pressure behavior of fractured gas wells assumed a single fracture of equal half-length emanating from the opposite sides of the wellbore. However, multiple fractures may result from explosive, tailored-pulse fracturing, and hydraulic fracturing treatments. This paper presents the results of using a polar-coordinate simulator to investigate the transient pressure behavior of gas wells with 4-wing, 6-wing, and 8-wing multiple fractures.

Results show that the dimensionless pressure, PwD, can be correlated with the dimensionless terms Cr = wkf/πkxf and xfrl2 = xf1/xf2 where Cr is the dimensionless fracture conductivity and Xfr12 is the fracture half-length ratio. The symbols, xf1 and xf2, represent the half-length of the primary fracture and the auxiliary fracture, respectively. Results also show that when Cr ≤ 10, multiple fracture transient pressure behavior is significantly different from that of a single-plane fracture.

A family of type curves was constructed using cross-plots of pwD vs. tDxf. Transient pressure data can be analyzed using these type curves to estimate the number of multiple fractures in addition to formation permeability, fracture length, and fracture conductivity. Errors of about 5% in fracture length and 28% in formation permeability could result from the use of singlefracture type curves.
Low-Permeability Reservoirs Development Using Horizontal Wells
Authors: Giger F. M.
Published: December 2007

In recent years, horizontal wells have played an increasing role as alternate production tools to vertical or slanted wells. Do they provide anything new to exploitation strategies for low permeability reservoirs ?

In this paper, we will contribute to answering this question by presenting results of analytical derivations pertaining to cases favorable to development with horizontal wells.

The effects of anisotropy related to shaly interbedding and natural fissuring will be discussed. The solutions and criteria are derived independently from the nature of the drive mechanisms because of their strong influence on the production profile of horizontal wells.

As some basic concepts usually applied in classical reservoir engineering to production with vertical wells have to be drastically re-evaluated when dealing with horizontal wells, the economic assessment of their spudding must be evaluated with new criteria. The new criteria, such as areal productivity and replacement ratio of vertical wells by horizontal wells, are introduced in order to help the decision-maker responsible for the exploitation of a low permeability reservoir.

The chief technical contributions of the paper are: –Criteria for comparing horizontal and vertical well productive efficiency.–Spatial depletion profiles around the horizontal well.–Areal productivity index and replacement ratio equations.
Devonian Shale Horizontal Well: Rationale for Wellsite Selection and Well Design
Authors: Yost A. B. , Overbey W. K. , Salamy S. P. , Okoye C. O. , Saradji B. S.
Published: December 2007

This paper discusses the rationale for selection of a well site where geologic and reservoir conditions are favorable for a horizontal well to increase gas recovery efficiency over that of vertical wells. In this effort, an area of favorable geology was selected and a multi-site reservoir evaluation study was conducted to determine an appropriate location for a long horizontal wellbore in the Devonian shale in southwestern West Virginia. Within a candidate reservoir, existing wells and their suspected directional properties were analyzed to develop the best candidates for location of the horizontal well. Reservoir data from over 38 wells in the area were used to establish areas of high flow capacity. A 3-dimensional gas flow simulator capable of modeling both fracture and matrix porosity and permeability and desorption were used to investigate both the adjacent well interference and production performance of a 2,000-foot horizontal wellbore. Final well location selection was based on minimum interference, high expected recovery efficiency, and reasonable access in rugged terrain.

Once site selection was completed, a well-planned drilling approach was developed based on a complete review of horizontal well drilling technology with particular emphasis on methods to directionally drill on air or air/mist to intersect the inherent fracture system (based on regional mapping trends), horizontal coring for natural fracture spacing, and multiple hydraulic fracturing horizontal boreholes through cemented casing. The lessons learned in this effort are that horizontal wells can be achieved in naturally fractured formations, but good reservoir studies are required to increase the probability of success in achieving noteworthy production.
Long-Term Performance of Proppants Under Simulated Reservoir Conditions
Authors: Much M. G. , Penny G. S.
Published: December 2007

The insitu performance of two classes of commonly used fracture proppants has been evaluated in the laboratory. Identification of the effects of time and stress on fracture proppants was determined and further, the effects of embedment and gel damage under downhole conditions was evaluated. Accurate fracture proppant parameters are now available.
Successful Field Application of High-Temperature Rheology of CO2 Foam Fracturing Fluids
Authors: Phillips A. M. , Couchman D. D. , Wilke J. G.
Published: December 2007

High temperature rheology of carbon dioxide foam fracturing fluids has been developed in the laboratory and successfully applied to improve the design of foam fracturing treatments of tight gas sands.

In the laboratory phase of the project, carbon dioxide foam properties were measured to 250°F (121°C) in a high temperature, high pressure pipe viscometer. The effects of foamer type and concentration on high temperature carbon dioxide foam rheology were determined. It was found that, above a certain level, further increases in foamer concentration provide little corresponding increase in foam stability or rheology. Carbon dioxide foam stability can be improved by the use of higher concentrations of gelling agent.

Test data indicates that higher concentrations of foamer and gellant are required to produce stable carbon dioxide foams, as compared to nitrogen foams. It was found that rheological data generated for nitrogen foams will not be sufficient to describe the same system when pumped as a carbon dioxide foam, as had been previously assumed.

Historically, foam fracturing design and fluid composition (gellant and foamer) have been based on rules of thumb and common area practice. The laboratory generated foam rheology and stability data were used to modify fracturing design and fluid composition. These design changes have resulted in more successful carbon dioxide foam stimulation treatments and have drastically reduced screen-outs. Examples of successful treatments utilizing the new design data will be compared and contrasted with historic treatments in several tight gas sands.
Examination of Potential Mechanisms Responsible for the High Treatment Pressures Observed During Stimulation of Coalbed Reservoirs
Authors: Jones A. H. , Bell G. J. , Morales R. H. , Schraufnagel R. A.
Published: December 2007

Treatment pressures observed during hydraulic fracturing of coal seams are often different than for conventional formations. In particular, there is usually an early, steep pressure rise and overall treatment pressures often exceed the lithostatic pressure, but produce surprisingly little vertical fracture extension. In addition, instantaneous shut-in pressures are high following a fracture treatment, while closure pressures after treatment are in good agreement with in-situ stresses determined prior to initiating hydraulic fracture stimulation. These responses cannot be explained by conventional modeling approaches. On the other hand, there are cases for coal treatments where pressures remain at levels comparable to other formations.

An investigation into the physical causes of the unusual behavior of coal seam stimulations resulted in the identification of a new physical mechanism for further consideration. The accumulation of coal chips at the wellbore and partial plugging of an advancing fracture tip by coal fines carried ahead of or within the fluid treatment pad are mechanisms which consistently explain all of the observed behavior.

Hydraulic fracture design codes, which include the description of the coal fines accumulation at the fracture periphery, were used to assist in the design of hydraulic fracture treatments at the Gas Research Institute, Multiple Coal Seam Field Project, at Rock Creek in Alabama, and were used to analyze the actual treatments.
On the Stimulation of a Northern North Sea Tight Sand
Authors: Despax D. , Charlez P. , Clinkemaillie J. , Economides M. J.
Published: December 2007

Thick reservoirs (about 100 m, 330 ft) have been discovered in the northern part of the North Sea, with effective permeabilities less than 0.1 md. In spite of this poor transmissivity, it has been planned to study the development of these blocks, lying under 160 m (525 ft) of sea water. Reservoir engineering evaluations have already suggested that profitability could be reached, but only if the wells are significantly stimulated. This is why an extensive fracturing feasibility study, focused on the Brent formation, was carried out.

The Brent formation appears to be a sandstone which would easily be stimulated using normal hydraulic fracturing techniques and this study has revealed (1) that sufficiently conductive propped fractures with fracture half-lengths at least equal to 150 m (500 ft) are feasible and have a reasonable chance of success, and (2) that this size of treatment will satisfy the production increase requirements.

However, it is not possible with the data available today to guarantee that this design would in fact reach the expected target in all drilled and planned wells. The main reason is that the minimum horizontal in-situ stress profile versus depth is not known and, that fully three-dimensional numerical simulations based on laboratory results have emphasized that 50 bar (725 psi) is the minimum excess pressure to contain a facture to less than 10 m (33 ft) of vertical growth and thus, to prevent fluid penetration in the underlying coal strata during the pumping period. In a coal layer, horizontal stresses are suspected to be very low and in the case of connection between such a layer and the perforations, the gel would preferentially fracture the coal rather than the sandstone, thus setting the proppant out of the pay zone. In-situ measurements of stress become essential for each relevant layer.
Drilling Contractor Proposes New Methods for Mud Solids Control Optimization on the Rig
Authors: Rodt G. , Cahuzac J. P.
Published: December 2007

In recent years the development of more sophisticated mud systems in the North Sea has drastically changed the concept of mud solids control on the rig. Getting a "better handle" on mud costs and reducing the pollution associated with losses on surface have become major concerns for the Operator and have resulted in a focus on the efficiency of mud mechanical treatment equipment.

This paper shows how an extensive and full scale test campaign has allowed a Drilling Contractor to develop new methods for the optimization of the use of shale shakers / mud cleaners / centrifuges. After a brief review of laboratory results, it describes field trials and shows how the use of sophisticated measurement devices and on site computer evaluation can lead to significant improvements in typical North Sea system operations.
Controlled Make-Up Procedures for Improved Workovers and Completions
Authors: Stewart A A
Published: December 2007

New developments in traditional equipment and practices in connection make-up have been analysed using a large-scale data-base gathered from a wide variety of locations in NW Europe. For the first time this has allowed valid comparisons of field performance from which practical recommendations can be produced and equipment specifications developed to improve the procedures for completions and workovers.
Two Years Experience with Use of Seabed Diverter
Authors: Klavenes P T , Leistad G H
Published: December 2007

Experience has proven traditional procedures for handling of shallow gas to be inadequate with respect to safety of operations. Equipment for diverting gas at the seabed was developed and put to use. Experience gained during two years now confirm that the seabed diverter improve safety of operations by offering preventive as well as corrective advantages. Shallow gas formations can be drilled using mud with density adjusted to formation integrity and pressures. In case of a shallow gas blowout gas can be kept away from the rig by diverting to the sea. If necessary the well can be shut in and the rig pulled off location in a controlled way.
Applications of Subsea Bottom-Hole Pressure Monitoring Systems in Reservoir Appraisal and Development
Authors: Scofield J. R. , Baxter C. F. G
Published: December 2007

This paper discusses the field performance of a remotely operated bottom-hole pressure monitoring system installed in a subsea appraisal well in the North Sea. Topics covered include vessel station keeping requirements during system interrogation, data recovery utilizing subsea accoustic telemetry, performance of the wellhead mounted data acquisition units, and downhole pressure gauge and electrical circuit reliability.

The paper also describes several applications for using subsea exploration wells as remote bottom-hole pressure and temperature monitoring systems to aid in reservoir appraisal and development. Applications covered include interference testing, extended pressure build-up surveys and waterflood pressure response monitoring. Completion techniques and measurement and recording systems are discussed which will permit single or multi-zone pressure and temperature readings to be made over specified time intervals for static bottom-hole conditions up to 15000 psia and 300°F. In addition, methods of employing the pressure monitoring completion to perform drill stem tests are detailed.

Lastly, there is a discussion of recommended improvements to completion installation techniques and data logging capabilities which will enhance overall system reliability and usefulness.
The Removal of Abandoned Beryl Field Pipelines and Structures
Authors: Brown A. R. , Peacock D. A.
Published: December 2007

Within the last 2 years Mobil North Sea Limited (MNSL) has removed from the Beryl field:- 7 kilometres of abandoned untrenched Coflexip flowline, and2300 tonnes of steel and concrete debris from a failed single point mooring – SPM1.

The Coflexip flowline was refurbished, tested and is being reused in the field this year. Recovery of SPM1 debris represents the first practical experience of large scale removal operations in the Northern North Sea.

With the passage of the Petroleum Bill the future removal of abandoned pipelines and structures is likely to be a major offshore activity. It is hoped that the experience presented herein will be of interest to operators, companies and legislative bodies.
Advanced Front-End Recovery Object or Simple Temporary Topside Facilities for Oil Production from the Rolf Field, Offshore Denmark
Authors: BRINK J
Published: December 2007

Crude oil (c. 10,700 BOPD) was produced through temporary topside facilities in the Rolf Field offshore Denmark from January 7th to September 27th, 1986. These simple, unmanned and remote controlled facilities were a low cost solution to a problem caused by delays of the permanent topside facilities. Project execution time was two months from start of conceptual design until start-up of oil production. Installation works were performed from a jack-up drilling rig – in part simultaneously with drilling operations. Materials and equipment installed were obtained with very short delivery times. The facilities which were certified by a Certification Society and approved by the Danish Authorities included all necessary safety features. Total costs for the facilities amounted to c. 1 million US$ (excl. rig time for installation). Due to simplicity high reliability of the production system was obtained. Availability of the facilities for the entire period from start-up was 99.6 percent. The facilities were manned 3.2 percent of the total operating time mainly due to wireline work for reservoir monitoring.

It is considered that the experience with the concept applied for the early production from the Rolf Field could form the basis for more simple and cost effective topside facilities for minor offshore fields.
High-Pressure Universal Volume Flowmeter for Cementing, Stimulation, Drilling, and Production
Authors: Codazzi D. , Mioque J. L. , Moncharmont J. A. , Montaron B.
Published: December 2007

A sensor capable of measuring the flowrates of fluids under pressure up to 15 000 psi (103.4 MPa) with an accuracy of ± 1% of the full scale, adjustable between 5.0 and 30.0 bbl/mn (0.79 and 4.77 m3/mn) in a standard 3″ line is presented. The device is completely non intrusive and operates with any kind of fluid encountered in the oilfield environment irrespective of its properties (e.g. electrical conductivity, rheology, presence of solid particles).

Applications of the flowmeter are discussed. Besides better control and evaluation of pumping operations, in cementing, stimulation and drilling, the readings are used to ascertain important parameters such as the bottom hole pressure or the total volume pumped. Another application more specific to cementing concerns mud removal. In addition, when the device is coupled with a flowmeter on the return line, differential flow measurement can be made permitting circulation losses and well kick detection.
Trends and Strategies for Drilling Computing
Authors: Payne M. L. , Church C. J. , Ng F. W.
Published: December 2007

There is currently considerable activity focused on implementing computing technology in the petroleum industry. In drilling, projects have included real-time field data acquisition for enhanced operations monitoring, databases for management of drilling information, drilling accounting systems for better cost control, drilling simulation for performance optimization, advanced numerical techniques for specific problems, office automation for personnel efficiency, and expert systems for solving rule based problems.

Priorities in these areas vary between operators. As a result, much more technology exists than has been implemented by any single operator. Because costs for these systems are substantial, most majors are incrementally building drilling computing systems on a priority basis that will ultimately address the full scope of the above functions. This paper reviews general background and current technology for drilling computing and details ARCO's current drilling computing environment and its visions for the future in the area.
The Effects of Quasi-Random Drill Bit Vibrations Upon Drillstring Dynamic Behavior
Authors: Skaugen E.
Published: December 2007

One of the main sources of drillstring vibrations is the interaction between the drill bit and the formation. Downhole measurements of forces and accelerations within the bottom hole assembly have shown that the vibrations at the bit have large quasi-random components, both for axial and rotational movements. These quasi-random vibrations are probably due to unevenness of the formation strength, random breakage of rock, and amplification of these effects by vibration mode coupling.

A drillstring dynamic model operating in the time domain has been developed in order to investigate the effects of these quasi-random vibrations upon drillstring behaviour.

It is shown that by including the observed, quasi-random vibrations, the drillstring dynamic behaviour may be substantially different from the behaviour predicted by the deterministic drillstring models used in earlier investigations. In particular, these models predict sharply increased vibration amplitudes when rotary speed is a certain subharmonic of resonance frequences in the drillstring. The model presented here shows that these resonance peaks are considerably reduced and smoothed out when the observed quasi-random nature of the drill bit vibrations is taken into account. The results of the model are compared to drillstring vibrations observed during drilling, and when using a downhole exciter.