bluuebunny/crossref_metadata_2025 huggingface dataset:
The Department of Energy's Western Gas Sands Project Multi-Well Experiment Update
Authors: Crawley Alex B. , Northrop Dave A. , Sattler Allan R.
Published: December 2007

The Department of Energy has initiated a Multi-well Experiment with the objectives: (1) characterization of low permeability, lenticular gas sands and (2) evaluation of state-of-the-art and developing technology for their production. The location is in the Rulison Field in the Piceance Basin, Garfield County, Colorado where the lenticular Mesaverde sequence and the underlying blanket Corcoran-Cozzette are the formations of interest and lie at depths between 4,000 and 8,600 ft.

Features of this research-oriented field experiment include: (1) three close-spaced wells (100 to 500 ft) for reservoir characterization, conventional well tests, interference testing, well-to-well geophysical profiling, and placement of diagnostic instrumentation adjacent to fracture treatments; (2) complete core taken through the formations of interest; (3) a comprehensive core analysis program; (4) an extensive logging program featuring conventional and experimental logs; (5) determination of in situ stress in sand lenses and bounding shales; (6) application of geophysical techniques to determine sand lens orientation; (7) use of seismic, electrical potential and tilt diagnostic methods for hydraulic fracture characterization; and (8) a series of stimulation experiments.

Analysis of data from these activities will yield the following kinds of information: (1) geologic characterization emphasizing the morphology, properites and variability of lenticular sands; (2) a reservoir model for lenticular sand production; (3) a fracture model including correlations between stress, geometry and lens orientation; (4) core-log-well test correlations for improved formation evaluation, and (5) economic assessments.

This paper is a survey of the findings to date. It includes a discussion of a study of the most relative outcrops; the drilling program; core analysis; and well-to-well correlation of the geology.

Two wells have been drilled, the first was continously cored through the Mesaverde section from 4,310 to 6,820 ft. In the second well, 950 ft of core was taken, which include all the zones of interest for stimulation experiments.

Significant overpressuring was encountered and a large number of fractures were observed in the core, some open up to 3/4-inch width with partial mineralization. Preliminary indications are that natural fractures may play a much larger role in gas production from the low permeability lenticular sand than had previously been thought.
A Comparative Analysis of Drilling Results Obtained with Oil Mud vs. Water-Base Mud at High Island Block A-270
Authors: Nance W. B. , Muncy D. D. , Garrett M. M. , Gault A. D. , Kortlang W. F.
Published: December 2007

Three wells on the High Island A-270B platform were drilled with water base muds and three were drilled with inverted emulsion oil muds. The drilling performance of these two mud types was compared for the six wells.

Overall drilling costs were significantly lower with the oil muds due to the elimination of differential pressure pipe and casing sticking.
Toroidal Coupled Measurements While Drilling
Authors: Smith H. C.
Published: December 2007

When drilling a well, data from downhole is currently brought to the surface primarily by mud pulse or wireline systems. This paper describes a unique system to accomplish this data transmission through the use of Electro-Magnetics (EM).
Rowan Arctic Rig 41—History and Operation
Authors: Gardner L. R.
Published: December 2007

Rowan Arctic Rig 41 is a diesel-electric, air mobile, Arctic development and exploration land rig. The rig was built in 1980 to meet the specifications of ARCO, ALASKA, INC. and is representative of current generation Prudhoe Bay development rigs.
Storage of Drilling Machinery
Authors: Makins J. E.
Published: December 2007

Storage of drilling machinery has typically consisted of simply "stacking" the rig in a yard until the next contract is obtained. In some cases a fresh coat of paint may have been applied to give the equipment some protection. To minimize machinery deterioration and subsequent start-up problems, more extensive protection is required particularly for extended storage periods. Suggested storage procedures for rig components are presented in this paper.
Techniques for Handling Upward Migration of Gas Kicks in a Shut-In Well
Authors: Mathews J. L. , Bourgoyne A. T.
Published: December 2007

This paper discusses the experimental evaluation of various proposed well control techniques which may be implemented when normal kill operations are delayed. Two 6000-ft wells, one containing the flow geometry present in a surface blowout preventer (BOP) stack and the other modeling the flow geometry of a subsea BOP stack in 3000 ft. of water, were used to evaluate (1) the constant drill pipe pressure method and (2) the static and dynamic volumetric methods that can be employed when a meaningful drill pipe pressure is not available. It was found that any of the three methods could be used to maintain an acceptable bottom hole pressure in a surface BOP system with a uniform annular geometry. However, the static volumetric method generally resulted in a decreasing bottom hole pressure once gas reaches the subsea choke line and is not recommended for deep-water floating drilling operations.
Where and How Not to Run PDC Bits
Authors: Keller W. S. , Crow M. L.
Published: December 2007

A comparison has been made of the results obtained with a new soft formation PDC bit (the Security STRAT-X Bit) and those obtained in a wide range of formations with the various types of PDC bits currently available. The results indicate that, at present, PDC bits are special products for special situations. The clearly superior results have been obtained in homogeneous soft formations when the bit hydraulics and application practices have been appropriate for the particular bit design involved. Very high penetration rates and significant reductions in cost/foot have been achieved when bit design, hydraulics, mud and application practices have been matched well with the bit characteristics. However, even the newest and most productive PDC bits cannot compete when the formation is unsuitable for the particular bit design in combination with the drilling fluid and the hydraulics available. A review of several specific examples in South Texas, the North Sea, and the Rocky Mountains illustrate what can be done with currently available PDC bits, and how to identify those circumstances under which PDC bits should not be run. The results also indicate how to identify when a formation change requires that a PDC bit be pulled or when one can drill through hard streaks and retain the high productivity of the PDC bit for the softer portions of the formation. Maintaining a full gage hole under these conditions is shown to depend critically on bit design and control of weight and rpm.
Analysis of the Invert Emulsion Oil Mud-Polycrystalline Diamond Bit System in Shallow Permeable Formations
Authors: Golis S. W.
Published: December 2007

Recent field experience with shallow, normal pressured wells in South Texas demonstrated an invert emulsion oil mud employed with a polycrystalline diamond compact (PDC) bit significantly increased PDC bit rate of penetration (ROP) and life. Each well used an invert emulsion oil mud from surface casing to total depth and a PDC bit to drill the majority of the same interval. This resulted in substantial cost savings compared to KCl/polymer and freshwater mud systems.

To realize the full cost savings potential, hydraulics and mud programs were designed to maximize PDC bit performance and minimize oil mud costs. This paper examines field results and develops a correlation between hydraulics and mud programs and optimum invert emulsion oil mud-PDC bit performance.
Potential Petroleum Source Rock Deposition in the Middle Cretaceous Wasia Formation, Rub'Al Khali, Saudi Arabia
Authors: Newell K. D. , Hennington R. D.
Published: December 2007

Stratigraphic correlation and regional geochemical sampling in the Rub'Al Khali (The Empty Quarter) of Saudi Arabia indicate at least two potential petroleum source rock units occur in the middle Cretaceous Wasia Formation. These two sequences, informally named the Safaniya "source rock" and the lower Mishrif, are dominated by oil-prone amorphous (Type II) organic matter, in places in excess of 10 weight percent organic carbon.

Both units are fine-grained pelagic lime mudstones which were probably deposited in relatively quiet anoxic waters of large intraplatform embayments or basins. The Safaniya "source rock" and the lower Mishrif reflect strong marine transgressions on the Arabian craton in Albian to Cenomanian and Cenomanian to Turonian time, respectively. Regressive-phase sedimentary rocks overlying these two transgressive organic-rock phases are generally poor in organic carbon despite being deposited, in part, in similar forereef open-marine depositional settings. The sea-level high-stands associated with the Safaniya "source rock" and the lower Mishrif are partly synchronous with two recently described "oceanic anoxic events" respectively occurring in late Barremian to late Albian time and late Cenomanian to early Turonian time. Although there is a credible time correlation of these organic-rock units with oceanic anoxic events, their connection to oceanic anoxic events could be strengthened if they could be traced out to the vicinity of the middle Cretaceous continental margin. Unfortunately, lack of information from adjacent areas prohibits determining the complete extent of the organic-rock units. The organic richness of these sediments could therefore also be the result of euxinic conditions locally developed within silled basins of the Tethys epicontinental sea.
Unique Ultra Light-Weight Cernent Slurry Compositions for Use in Unique Well Conditions, Laboratory Evaluation, and Field Performance
Authors: Tanner C. H. , Harms W. M.
Published: December 2007

In many areas of the Middle East severe lost circulation problems encountered while drilling and cementing are commonplace. However, due to recent technological developments in ultra light weight cement compositions the feasibility of obtaining mud and cement returns in these situations has been greatly improved.
Evaluation of Stimulation Treatments in Appalachian Tight Gas Sands
Authors: Charles J. G. , Hudock K. D. , Udick T. H. , Hall D. R.
Published: December 2007

Hydraulic fracturing is the most common method used to improve production from wells drilled into "tight" formations. Accurate fracture design is essential in order to obtain highly conductive and deeply penetrating fractures. In the past, many stimulation treatments in the northeastern United States had little basis for design. Thousands of wells have been fractured and comparative analysis of different techniques was extremely difficult. This paper attempts to evaluate fracture design in relation to tight gas sands in the northeast.

A review of the major variables affecting hydraulic fracture design is included and a discussion of three pressure transient methods used in the evaluation is presented. Pressure buildup analysis was used to determine effective reservoir permeability and pressure. Type curve matching was used to approximate fracture lengths and to predict production resulting from changes in fracture geometry. Computer reservoir simulation analysis helped in more accurately modeling the reservoir to support the production forecasting.

A case history detailing this method of evaluation in the Medina Formation is discussed. Actual field data are compared to the predicted results.

A field study is also presented which deals with the "Clinton" formations in Ohio. A number of wells were evaluated (after stimulation) with type curves and some ideas on job designs are suggested.
Decline Curve Analysis in Fractured Low Permeability Gas Wells in the Piceance Basin
Authors: Stright D. H. , Gordon J. I.
Published: December 2007

Production decline curves of three representative low permeability gas wells in the Piceance Basin are analyzed. These wells produce from theMancos "B", Mesaverde and Wasatch formations, respectively.

It was found that long term production in these wells could be approximated using linear flow equations. This observation leads to the development of a decline curve method for predicting rate-time behavior based only on one or two years of production data. The method is easy to applyand requires only data which is routinely reported to state oil and gas regulatory agencies. This type of data is public information and is readily available in most states.

The observed long-term linear flow behavior indicates that fracture lengths are much longer than would beexpected from hydraulic fracturing treatments. Possible explanations forthis behavior are discussed. The possibility of using short-term test data to define the long-term production decline curve is also discussed.
Three-Dimension Reservoir Simulation, Sadlerochit Formation, Prudhoe Bay Field
Authors: Thayer P. T. , Puente P. G.
Published: December 2007

A three-dimensional, three-phase reservoir simulator has been used to "model" the reservoir behavior of the Sadlerochit Formation, Prudhoe Bay Field, Alaska. The main objectives of the study are: To examine the effect of various proposed operating conditions on gas reserves and deliverability.To conduct sensitivity studies to determine optimum operating strategies from the gas purchaser's point of view.To monitor field performance in order to identify possible areas of concern to the gas purchaser.

A primary goal of the study was to develop a fairly small and simple model, easy to update, which could be used to run a large number of different cases at a reasonable level of computer cost.

To date, a very good history match has been obtained. That match has been updated three times with additional production and completion data and several prediction runs have been made.

This paper will describe the methods used to develop certain input parameters for the model, the process of calibrating the model with past production (history match), and the results of prediction runs.
A Field Proven System for Selective, Multizone, One-Trip Gravel Packing
Authors: Jefferis R. G. , Bruist E. H. , Botts T. M.
Published: December 2007

Newly developed inside casing gravel packing tools have been combined with slurry packing techniques and gravel pack logging to provide a highly successful, field tested, gravel pack system. The system allows multiple, isolated zones to be selectively gravel packed with only one trip in the hole. The one-trip feature of the system not only allows long, multiple zone wells to be completed quickly, but it also reduces and simplifies the number of operations resulting in a more dependable and relatively trouble-free completion method.

The paper describes the design and operation of the gravel pack tools and liner assembly, the fluids used in the gravel packing, and the application and interpretation of the gravel pack log. A summary of the experience gained with the system to date is also given.
The Application of In-Situ Steam Foams To Improve Recovery in Mature Steam Drives
Authors: Eson R. L. , O'Nesky S. K.
Published: December 2007

Gravity segregation (steam override) and poor areal and vertical sweep efficiencies have limited recoveries in many heavy oil reservoirs since the first thermal projects were initiated in the 1960's. In many instances the injected steam prematurely breaks through into producing wells creating steam channels. In-situ steam foams have proven effective at reducing the mobility in these steam channels and diverting the injected steam into alternate flow paths, thus improving the sweep efficiency of the steam drive process.

This paper describes the efforts associated with the performance under two Department of Energy (DOE) cost-sharing contracts to reduce steam channeling in a conventional steam drive using in-situ steam foam additives. Three steam injection patterns, each being treated with a different steam foam additive, will be presented. In each of the cases, the steam foam additive altered the sweep efficiency and incremental oil production was noted. The cost to produce an incremental bbl of oil varied from $1.50 to $48.81.
Viscous Fingers and Gravity Tongues in CO2-Steam Stimulation
Authors: Claridge E. L. , Dietrich J. K.
Published: December 2007

The presence of highly viscous bitumen and absence of an initially mobile water phase in the Cold Lake (Alberta, Canada) Upper McMurray formation reduced the tendency for CO2 viscous fingering (unstable frontal advance) to occur in simulations of the cyclic CO2/steam process. Highly-cemented sandstone lenses within the bitumen column were shown to produce local gravity over-ride of the injected CO2 and displaced hydrocarbon gas, thereby creating gravity tongues which resemble viscous fingers.

Use of CO2 additive to stimulate bitumen containing hydrocarbon solution gas under partially-depleted reservoir conditions was shown to decrease the bitumen recovery expected from application of steam alone. An encouraging observation is the deep penetration of the CO2 additive, which is expected to accelerate interwell communication and "condition" the reservoir for a steamflood.
Thermal Efficiency of a Steam Injection Test Well with Insulated Tubing
Authors: Aeschliman D. P. , Meldau R. F. , Noble N. J.
Published: December 2007

A field test of bare 2.375-in and insulated 4.500-in tubulars has been conducted using heat flux sensors and thermocouples to evaluate bare and insulated tubular performance, annulus heat transfer, and overall wellbore heat loss in a cooperative effort between Sandia National Laboratories and Husky Oil Operations, Ltd. The well is part of a steam flood pilot in the Aberfeldy Field near Lloydminster, Saskatchewan.

Insulation thermal conductivity was observed to vary by a factor of four between competing designs. Couplings and internal structures (e.g., centralizers) were seen to account for up to half the string heat loss with the annulus dry. For a wet annulus, the typical field case, steam generated at the hot couplings refluxed in the vented annulus and maintained the casing temperature constant at 212F at all points. Thus wellbore heat loss was 3-6 times higher than expected, the same opposite the highest and lowest quality insulated tubing, and only 30-40 percent less than bare tubing.

Insulated couplings or techniques to eliminate annulus steam refluxing are needed to achieve the potential of insulated tubing.
Deepwater Advanced Diving Systems That Support the Offshore Oil Field
Authors: Carnevale S. J.
Published: December 2007

This paper reviews deepwater diving technology which provides offshore oilfield support during all phases of exploration, construction and production. Mobile Observation Bells (MOB), Atmospheric Diving Suits (ADS), Remotely-Operated Vehicles (ROV), and saturation diving techniques are discussed. The term "deep water" is defined in relation to the water depths off the U.S. west coast. All diving system parameters are analyzed for each alternative; cost-effectiveness and safety are the two main objectives. Specific jobs are described which have used this high technology equipment for offshore operations on the U.S. west coast. These include drilling rig support, platform inspection and maintenance, and pipeline construction. Finally, future developments in diving systems will be discussed.
Laboratory Measurements of Mechanical Properties of Sandstones and Shales
Authors: Senseny P. E.
Published: December 2007

Laboratory tests were performed on specimens of sandstones, shales, siltstones and mudstones from thirty horizons in the Piceance Basin in support of the DOE Western Gas Sands Project Multi-Well Experiment. The objective of these tests was to determine tensile strength, compressive strength and elastic constants. Data obtained show that these properties vary substantially from horizon to horizon, and do not correlate well with either lithology or depth.
The Multiwell Experiment Core Program
Authors: Sattler A. R.
Published: December 2007

The Multi-Well Experiment (MWX) is a research- oriented field laboratory and it is the major pro-duction technology activity of the Western Gas Sands Project. A major activity is the core analysis program. Over 3600 ft (1097 m) of core were taken from two wells separated by only about 110 ft (34 m) at depth. All major categories of core analysis are reviewed and results through December 1982 are included. Those include routine core analysis, restored state reservoir parameter measurements, electrical measurements, mechanical rock property data, mineralogy, organic maturation and geochemistry. This paper also describes the laboratory work on core and formation invasion and the development of instruments that were used in the field processing of the core.
Reverse-Phase Ion-Pair Chromatography (HPLC) of Alkylbenzene Sulfonates
Authors: Verkruyse L. A. , Lewis R. V. , Meyers K. O. , Salter S. J.
Published: December 2007

A high-performance, liquid-chromatographic procedure is presented that rapidly and quantitatively separates alkylbenzene sulfonates according to their alkyl chain length and structure. The separation employs octadecylsilanized silica gel as a stationary phase and an aqueous acetonitrile solution of tetrabutyl ammonium chloride (TBAC) as the mobile phase. The TBAC acts as an ion-pair reagent and suppresses the ionic nature of the sulfonates. Separation is effected by gradients in TBAC concentration and mobile phase polarity. The concentration of each component is then quantitatively measured by a UV detector. Gradient selection and sample matrix effects are discussed. Several examples are presented that demonstrate the utility of this analytical procedure.
Gelatinous Oil-Base Fluids as Insulators in Geothermal and Oil-Recovery Applications
Authors: Son A. J. , Dzialowski A. K. , Loftin R. E.
Published: December 2007

The use of a thixotropic gelatinous oil-base fluid as an insulating medium in different oil field applications has become increasingly important. Its economic advantage over tubing/casing insulators makes it very attractive. It has proven itself as a successful thermal insulator in the field, particularly in steam injection projects. The data generated in the field, related to its thermal characteristics, are difficult to correlate because so many variables exist from well to well. This investigation was undertaken to define some properties, under more controlled conditions, that would promote more efficient utilization of the thixotropic gel. Heat transfer coefficients were generated so that its efficiency as an insulator can be rated relative to other insulators. Thermal expansion coefficients, derived in the study, are much needed in engineering calculations such as volume requirements, tubing/casing strength, etc. Behaviour of the insulating gel at 700°F and 10,000 psi and static gel strength at various temperatures were also determined to answer questions on temperature limitations and pressure requirements for placement and displacement.
Selective Gas Shut-Off Using Sodium Silicate in the Prudhoe Bay Field, AK
Authors: Herring G. D. , Milloway J. T. , Wilson W. N.
Published: December 2007

To alleviate excess gas production in the Prudhoe Bay field, a non-rig gas shutoff technique using sodium silicate has beer-developed. An activated sodium silicate mixture is squeezed through coiled tubing into the gas producing intervals where it gels into a gas impermeable barrier. In addition, a temporary bridging agent has been successfully used to isolate oil producing intervals during a squeeze. This technique utilizes coiled tubing and can be accomplished for approximately 25% of the cost of a standard rig workover at Prudhoe Bay.
Pressure and Temperature Effects on Brine Completion Fluid Density
Authors: Thomas D. C. , Atkinson Gordon , Atkinson B. L.
Published: December 2007

A model has been developed to predict the density of a brine containing CaCl2, CaBr2) and ZnBr2 from its composition. The model accounts for the effects of pressure and temperature using experimental results and literature data. The theoretical framework and equations used are presented.

Brine completion fluids are used to control wells during gravel-packing and other open perforation completion work. Since they are usually filtered to minimize particulate invasion, careful adjustment of the overbalance pressure is required to minimize fluid loss to the formation. The methods presented here will allow the engineer to more accurately estimate the density requirements for the fluid.

The model has been compared to published brine density data and matches that data well. The model predicts the effects of temperature on CaCl2, CaBr2 and ZnBr2 solutions. The effect of pressure on these fluids is small and less documented, but where data are available for comparison purposes the model matches the data well up to 200°F.

Methods of predicting the density of brine completion fluids are needed for well control pressure calculations and cost control of fluids, and are major factors in brine completion fluid optimization. This work represents the first application of modern solution thermodynamics to field completion brine problems.
Identifying "Clean" and Productive Zones From Well Logs
Authors: Ebenhact B. W. , Ransom R. C.
Published: December 2007

There are many techniques available to determine shaliness and potential from well logs. Each of these techniques has. its own limitations, which must be remembered when applying them. This paper reviews the techniques and discusses means of improving the interpretation by comparing information from many methods.
Modeling of Asymmetric Vertical Growth in Elongated Hydraulic Fractures and Application to First MWX Stimulation
Authors: Palmer I. D. , Craig H. R.
Published: December 2007

When a continuous sand is bounded by zones of higher, but unequal, minimum in-situ stress, a vertically asymmetric hydraulic fracture results. The modeling is much more difficult than in the symmetric case mainly because the width equation is harder to formulate and solve. In this paper we present the principal components of the modeling, which includes non-Newtonian flow, leakoff with spurt loss, and "storage" of fluid due to volume expansion. The assumption is that the fracture is highly elongated, i.e., stress contrasts between pay and bounding zones are relatively large (≳ few hundred psi). Vertical gradients of minimum in-situ stress and fluid pressure can be included in the modeling. To illustrate, the results, we present design calculations for a 30,000 gallon fracture, which was the first stimulation in the Multi-Well Experiment. The 80 ft fracture interval in the Paludal zone has at its upper edge a 520 psi stress contrast, and at its lower edge a 1195 psi contrast. Computed fracture height growth above and below the perforated interval, bottomhole pressure, and width profiles in vertical sections are displayed. Comparison is made with diagnostic measurements of fracture length, height, and bottomhole pressure.
Aqueous-Based Fluids for Perforating and Oil-Phase Mud Removal
Authors: Goode D. L. , Stacy A. L.
Published: December 2007

Wells drilled with oil-phase muds are subject to severe damage due to loss of mud filtrate or whole mud to the reservoir matrix or hairline fractures. It is essential that this mud be removed prior to well production in order to gain maximum productivity. Because of the severity of this mud damage and the ineffectiveness of conventional treatments, a system of aqueous-based remedial treatments was developed to remove oil-phase drilling muds from damaged reservoirs. Mud solids are suspended and mud viscosity is permanently lowered by the aqueous-based system so that the mud can be flowed to the surface. Special surfactants restore the affected rock surfaces to a water-wet state. The system can also be formulated in high-density brines for spotting and perforating. The system's thermal stability enables it to be used for extended periods of time at elevated temperatures.

The aqueous-based system represents an improvement over conventional hydrocarbon/mutual solvent treatments. The conventional treatments do not effectively suspend mud solids and only temporarily reduce mud viscosity, while leaving the treated rock surfaces in an oil-wet condition. In addition, hydrocarbon-based fluids require substantially higher pressures for placement in the well than the aqueous-based system.

Laboratory data are presented showing the relative effects of the aqueous-based system and a conventional hydrocarbon/mutual solvent treatment on the degree and permanence of oil-phase mud viscosity reduction. The aqueous-based system more effectively and irreversibly lowers mud viscosity, as compared to the hydrocarbon/mutual solvent treatment. Cores damaged by oil-phase mud filtrate or whole mud were treated with either hydrocarbon/mutual solvent or the aqueous-based system. Regained core permeabilities following the treatments indicate that the aqueous-based system yields significantly higher permeability recoveries than the hydrocarbon/mutual solvent treatment.

The aqueous-based system has been widely used in wells drilled with oil-phase muds to effect significant production increases. These remedial treatments have more effectively removed damaging oil-phase mud filtrate and solids than conventional hydrocarbon/mutual solvent treatments.
An Analysis of Post-Stimulation Production Response in the Madison: Elk Area, ND
Authors: Cramer D. D.
Published: December 2007

Madison carbonates in the Williston Basin vary-widely in productive capacity. Often, wells achieving low oil production rates after acid stimulation respond favorably to a proppant fracturing treatment. This has occurred most frequently in fractured reservoirs with limited matrix permeability (less than 0.1 md).

The study area- consists of nine contiguous fields 10-15 miles south of the town of Williston, North Dakota. Madison reservoir development was initiated in 1980 and has proceeded steadily. A variety of stimulation techniques have been, implemented with proppant fracturing emerging as a frequently used method. This paper reviews and evaluates area reservoir characteristics and completion and stimulation practices. Also included is an analysis of the reservoir behavior during proppant fracturing treatments and of the ensuing production response. In most cases, proppant fracturing techniques have provided better productivity increases than large-scale acidizing and lower than normal decline rates.
Sand Arching - A Case Study
Authors: Risnes Rasmus , Bratli Rolf K. , Horsrud Per
Published: December 2007

The theory for stability and failure of sand arches and cylindrical holes has been applied to actual well test data. The formation tested was a poorly consolidated oil bearing sand. The well was perforated in the actual interval, but no special sand control equipment was installed. The test procedure consisted in measuring simultaneously sand and oil production as the choke size was stepwise increased. In this way the maximum sandfree production rate was established.

Analysing the data, it can be concluded that the theory for arch and hole stability is capable of describing consistently the observed results.
Explosionproof Electric Unit Heating Systems for Offshore Rigs
Authors: Epstein F. S. , Arekapudi A. K.
Published: December 2007

We have developed an explosionproof electric unit heater system to operate in ambient temperatures down to -30° F. (-34° C.) [-70° F. (-57° C.) with modification]. The self-contained system includes a blower, heating elements, controls and provisions for focusing the warm airstream on personnel up to 20 feet (6.1 meters) away. Ratings up to 91 KW (310,000 BTU/HR) will provide air temperature rises as high as 164° F. (91° C.).
Explosive Cutting of Stuck Drillpipe and Bottomhole Assemblies
Authors: Nimmo P. , Kamp A. W. , Leiper F. J.
Published: December 2007

Conventional back-off equipment has been used for many years to disconnect fran a stuck drill-string. The success rate in backing-off drill collars has been low, decreasing markedly with depth and deviation. This has often resulted in abandoning most of the expensive BHA components. This paper introduces a new explosive technique which allows cutting or back-off directly above the stuck point within the BHA components if necessary. Field evidence is also presented showing that- this technique provides a higher chance of success than conventional explosive methods, which have tended to rely on backing out a connection rather than cutting within the assembly.
The Wellsite Use of Luminescence Fingerprinting to Differentiate Oil-Base Drilling Fluid and Native Hydrocarbons
Authors: Summers C. F. , Geraghty S. , Holliday G. C. , Bell R. E. B.
Published: December 2007

The development of a procedure, based on the application of synchronous luminescence spectrometry to the problem of differentiating crude oil and oil base drilling mud, is described. Its performance is illustrated by reference to field data from serveral North Sea wells. This 'fingerprinting' tool effectively simplifies interpretation of formation samples which are otherwise confused by the presence of oil mud filtrate.
PDM vs. Turbodrill: A Drilling Comparison
Authors: DeLucia F. V. , Herbert R. P.
Published: December 2007

This study was undertaken to investigate and compare the two most prevalent down-hole motor types, Positive-Displacement and Turbodrill. The intent of this comparison was to evaluate the technical and operational performance characteristics and present them in a manner to aid the drilling contractor or drilling engineer in determining the best down-hole motor for a specific drilling application. Each type of drilling tool utilizing either power source possesses unique characteristics which can be tailored to the overall system to optimize the target objective; increase ROP at less cost.
Cementing Temperatures for Deep-Well Production Liners
Authors: Wooley G. R. , Giussani A. P. , Galate J. W. , Wedelich H. F.
Published: December 2007

Temperature of cement is an important factor in properly cementing deep well production liners, yet current methods of determining cement temperatures do not account for all variables. In this paper a computer model predicts temperatures of cement while pumping and while waiting on cement, compares computed and measured temperatures, defines the importance of certain cementing variables on temperatures, and provides an explanation of difficulties encountered while cementing liner tops.
Long-Term Control of Paraffin Deposition.
Authors: Woo G. T. , Garbis S. J. , Gray T. C.
Published: December 2007

Paraffin-related problems occur in almost all oil producing areas throughout the world. These problems can be encountered in any part of the production system from the time the crude leaves the reservoir until it reaches the refinery. As a result, operators spend a large amount of time and money to correct paraffin-related problems.

Traditionally, operators have been forced to remove paraffin deposits from downhole equipment, tubular goods and surface equipment using mechanical, thermal or chemical methods. In many cases, a combination of two or more methods are employed. The major disadvantage of these methods is that they treat paraffin-related problems after they have occured.

The treatment of wells with dispersants and paraffin deposition inhibitors generally reduces or slows paraffin build-up. However, this inhibition is often very short-lived, because the well production quickly carries the chemicals to the surface. The addition of a long-term solid paraffin deposition inhibitor with the proppant during a hydraulic fracturing treatment has proven to extend this inhibition time. The solid paraffin inhibitor slowly releases the paraffin inhibitor chemical throughout the early production of a well.

This paper will describe a laboratory simulation of paraffin deposition used to evaluate two paraffin inhibitors in nine etudes. The two paraffin inhibitors evaluated were: (1) a blend of crystal modifiers in a controlled-release matrix form and (2) a commiercially available ethylene-vinyl acetate copolymer solid. One field evaluation presented compares the long-term effectiveness of both paraffin inhibitors. In a second field evaluation, the blend of crystal modifiers was used in two wells to successfully control paraffin deposition. In both field evaluations, the blend of crystal modifiers in a controlled-release matrix form has successfully prevented paraffin deposition.
Numerical Computation of Temperature Distribution in a Wellbore While Drilling
Authors: Corre B. , Eymard R. , Guenot A.
Published: December 2007

There is a need for determining temperature profiles in and around a wellbore during drilling phases. A computer model has been developed.

To take into account an evolutive geometry at the level of the tool, an adaptive grid refinement was used; it ensures a better physical representation. The unknowns are the temperatures at the center of each grid block and of each interface. The non-linear equations are discretised in finite-difference fully implicit scheme and solved by the Newton's method.

Complex rheological models are used to improve fluid mechanics' representation. At any location and time, the flow nature is determined and then pressure losses and connective heat transfer coefficients are calculated. Energy source terms are function of location and time.

Any flow history and drilling sequence may be simulated. Typical drilling sequences are presented. This model has been used in order to design mud and drilling programs to ensure a better hole stability.
A Simplified Predictive Model for CO2 Miscible Flooding
Authors: Paul G. W. , Lake L. W. , Gould T. L.
Published: December 2007

The purpose of this paper is to present a rapid, inexpensive, and reliable method for the economic evaluation of CO2 miscible flooding. The method consists of a reservoir model for the prediction of oil, water, and CO2 rates, combined with an economic model for the calculation of discounted cash flow and other profitability indices. The model is validated against field floods, laboratory data, and numerical simulation. Model predictions of the sensitivity of profitability to some reservoir properties and operating variables are presented.
Subsea Hydraulic Power Generation and Distribution for Subsea Control Systems
Authors: Pipe Tony
Published: December 2007

This paper is designed to outline the hydraulic aspects of subsea control system. To familiarize the reader, various system configurations and their particular applications are discussed. A detailed discussion on the major features of a hydraulic control system is then followed by a description of a typical manifold system and actual characteristics of an existing system.

The paper outlines important aspects such as hydraulic fluid selection and maintenance, specifications for hydraulic power units and subsea control lines, selection of valve actuators and the interfacing of equipment both at the design and installation phases.
Diverting and Controlling Offshore Subsea Blowouts
Authors: Hammett D. S.
Published: December 2007

This paper presents a concept for diverting and controlling a subsea blowout to prevent major pollution in shallow or deepwater ocean areas. The concept has been developed, model tested, and several of the concept components have been utilized in the field.

Several blowouts have occurred which have resulted in oil and/or gas flowing from a subsea well or BOP. The flow, when it reaches the ocean surface, must be collected. The concept reported in this paper diverts the subsea well flow to a collection vessel before the flow reaches the surface. A funnel with riser suspended from a barge is positioned over the subsea well. The well flow, which contains gas, lightens the fluid column inside the riser and the well fluids flow up through the riser to the collection barge. Once the well flow is diverted, a method of entering and stopping the well flow from the well bore is available via the funnel and riser. This complete system, the model tests, the field application, and the future use of the diverting and controlling procedures are reported in this paper.
Effects of Field Wear on PDC Bit Performance
Authors: Cheatham C. A. , Loeb D. A.
Published: December 2007

Laboratory drilling tests were conducted using a new 8 1/2 inch(216 mm) polycrystalline diamond compact (PDC) bit to determine optimum operating conditions for subsequent field use. The bit was then run on rotary in a shale formation at 14 506 ft(4421 m). Rate of penetration measured in the laboratory agreed closely with that observed in the field. Laboratory tests with the field-worn bit showed that to achieve the same rate of penetration as the new bit, the worn bit required three to eight times as much weight-on-bit and two to four times as much torque. Results indicate that, regardless of wear, maximum rotary speed should be used in medium-hard shale to obtain highest rate of penetration.
Long Reach Drilling In the Gulf of Mexico: A Case History
Authors: Whitson C. D. , Sandison G. F.
Published: December 2007

The Gulf Coast Main Pass 30 #1 Wildcat was spudped in November, 1983, and successfully drilled to a depth of 14,828 ft. MD – 7164 ft. TVD (See Figure 1). The average angle was 71° and the total horizontal displacement was 11,255 ft. The well was drilled from a surface location in Breton Sound Block 56 because of restrictions governing the placement of structures in Main Pass 30, which is located in a shipping fairway and anchorage area (See Figure 2 & 3).

The success of long reach well depended primarily upon the development of a thorough well plan and the close monitoring of drilling progress. In planning the well, drilling personnel paid close attention to the directional, casing, mud, surveying, and logging programs. Each was planned to accommodate the severity of the well geometry. Numerous options were considered for each phase before final decisions were made. Recently developed technology was used to great advantage e.g. measurement while drilling tools (MWD), slow speed-straight hole drilling motors, and drill string conveyed logging tools. This paper will outline the approach taken in planning and drilling the well and discuss possible improvements which could be made in future long reach wells.
The Evolution of Arctic Drilling Equipment
Authors: Holley G. T.
Published: December 2007

Since Arctic drilling and production programs in Alaska were undertaken over 20 years ago, the contract drilling industry has met and continues to meet the challenges of remote Arctic areas. Special drilling techniques and equipment have been developed to handle operations in the hostile environment. With most of Alaska's onshore and offshore areas remaining to be explored, the outlook for years of continued drilling looks good with new challenges for the industry ever present.
Water-Soluble Polymer Adsorption from Saline Solutions
Authors: Shah S. , Heinle S. A. , Glass J. E.
Published: December 2007

The adsorption of various polysaccharides on peptized montmorillonite is examined and their influence on the fluid loss properties of polymer-modified bentonite drilling mud (14 lb/bbl) formulations is studied as a function of increasing solution salinity and temperature. The studies indicate that adsorption per se does not facilitate fluid loss control, but adsorption is necessary in saline solutions. The ability of an anionic polymer to effect fluid loss control is related to the nature and amount of anionic substituent in the polymer (i.e., the total ionization of the macromolecule).

Mechanistically the data can be interpreted in terms of minimization of the electrical repulsive forces of the anionically charged water-soluble polymer and montmorillonite surface, with adsorption of the polyelectrolytes on the clay's surface positive edges.
Molecular Size Studies of Degraded Fracturing Fluid Polymers
Authors: Gall B. L. , Raible C. J.
Published: December 2007

Effective degradation of fracturing fluid polymers is necessary to minimize fracture and formation damage to allow rapid fluid return and economic production of gas (and/or oil). In this study, size exclusion chromatography (SEC) was used to investigate degradation of water-soluble polymers, such as modified guar and cellulose polymers.

SEC was used to monitor the decrease in molecular size of the polymer degradation products using oxidant breakers in the temperature range 343 K to 370 K (158°F to 205°F). SEC, however, was capable of monitoring the effects of polymer type and concentration, breaker type and concentration, break time and temperature. The SEC results were then correlated with solution fluid loss characteristics and residue production to define the molecular size reduction needed to minimize damage to a propped fracture. Results were compared to sandpack damage studies reported in the literature. Greater insoluble residue production required greater molecular weight reduction to minimize damage. SEC results were also correlated with solution viscosity. Measured viscosities depended on polymer concentration and degree of polymer degradation. Low solution viscosity did not guarantee reduction of polymer molecules to a non-damaging size.

SEC analysis should also be useful for evaluating new or improved breaker and polymer systems. Presently available breaker systems (in the temperature range of this study) did not provide both high initial solution viscosity and efficient molecular size reduction to minimize damage.
Potential Use of Nonionic Surfactants in Micellar Flooding
Authors: Verkruyse L. A. , Salter S. J.
Published: December 2007

A micellar flood was run in a Berea core using an isomerically pure nonionic surfactant. Phase behavior studies, interfacial tension measurements, and adsorption tests were conducted prior to flooding. High solubilization parameters, low interfacial tensions, and acceptable adsorption values were obtained for this surfactant. Nonetheless, the micellar flood failed to recover the anticipated amount of oil. Compositional analyses of flood effluent indicate that the micellar slug fell apart resulting in an increase in interfacial tensions and significant surfactant loss due to partitioning into the oleic phase.
Laboratory Evaluation of Sodium Hydroxide, Sodium Orthosilicate, and Sodium Metasilicate as Alkaline Flooding Agents for a Western Canada Reservoir
Authors: Larrondo L. E. , Urness C. M. , Milosz G. M.
Published: December 2007

The performance of sodium hydroxide, sodium orthosilicate, and sodium metasilicate solutions in oil recovery was evaluated in displacement tests using core samples and fluids from a Western Canada sandstone oil reservoir. Each core plug was first waterflooded with the formation (produced) brine and then resaturated with the reservoir oil before being treated with a given alkaline solution. The latter was injected either continuously or as a slug. Up to 2 pore volumes injected (PVI) of alkaline solution, 0.3 weight percent sodium hydroxide and 1.0 weight percent sodium metasilicate recovered the largest amount of additional oil. At higher PVI, 0.3 and 1.0 weight percent sodium hydroxide solutions recovered more additional oil than all other solutions. The oil recovery from the alkaline slugs (0.5 to 0.66 PV) was poorer, possibly because most of the alkali injected was consumed through reactions with the rock and reservoir fluids.

Emulsification and interfacial tension measurements as well as alkali consumption data suggest that all of the alkaline solutions used in the displacement tests should have had similar performance. The differences observed in the oil recoveries could be explained in terms of mineral and/or structural heterogeneity of the reservoir rock. In addition, the effects of freezing part of the sample in liquid nitrogen may have played a role in the observed performance of the alkaline solutions.