bluuebunny/crossref_metadata_2025_split huggingface dataset:
Protective Colloid System Improves Solids Removal Efficiency, Drilling Fluid Stability, and Drilling Performance
Authors: Clark D. E. , Daniel S. 
Published: December 2007

ABSTRACT
The utilization of a partially hydrolyzed polyacrylamide (PHPA) as a protective colloid in over 300 wells on the Louisiana and Texas Gulf Coast has shown evidence that this type of fluid not only stabilizes well bores, but has many other advantages which increase drilling performance and reduce overall drilling costs. The use of this system has demonstrated high rates of penetration, longer bit life, less stuck pipe and less mud to dispose of than other water base systems.
The observed decrease in drill cutting dispersion exhibited by this fluid results in increased solids removal efficiency by the solids control equipment. The resulting low colloid content drilling fluid, in combination with the PHPA, favorably affects all drilling parameters.
The rheological properties exhibited indicates minimal viscosity at the bit, resulting in higher rates of penetration. Increased hole cleaning ability is observed, which also contributes to decreased torque, drag, and stuck pipe.
The low colloid solids content/PHPA combination results in a thin, slick filter cake. Such a filter cake has minimized torque, drag, and stuck pipe.
The utilization of a dependable water meter, combined with a set of simplified equations, allows the solids removal efficiency and polymer additions to be calculated on a daily basis. Comparisons between numerous offset wells has demonstrated improved solids removal efficiency, drilling fluid stability and drilling performance.
Lost Circulation: A Solution Based on the Problem
Authors: Gockel J. F. , Gockel C. E. , Brinemann M. 
Published: December 2007

ABSTRACT
Lost circulation requiring positive treatment can best be solved by using materials similar in structure to the formation involved. Use of a vitrified, mineral-based granular material is best suited to this purpose because of its wide range of applicability and the unique features which this type of processing produces.
Case History of a 22,000-ft Deepwater Wildcat
Authors: Gordy C. A. , Combes J. F. , Childers M. A. 
Published: December 2007

ABSTRACT
Chevron U.S.A. Inc. recently drilled a 22,000 ft., deep-water wildcat in the Eastern Gulf of Mexico with Odeco's Ocean Rover. The Destin Dome Block 422 well, in 600 ft. of water, set three world records for wells drilled from floating vessels.
A number of operational and technical challenges resulted from this combination of drilled depth and water depth. These included casing design, subsea equipment design, rig design and selection, drill string design and unique logistical requirements.
This paper presents a case history of the well and emphasizes how joint planning and good operator/contractor cooperation can contribute to operational success. Results will show that a conservative, methodical approach with careful planning yielded a near trouble free operation on a high cost, critical well.
Incentive-Type Contract Improves Rig Performance
Authors: Cahuzac J. P. 
Published: December 2007

ABSTRACT
Incentive type drilling, uncommon in the drilling industry during the boom period several years ago, is currently generating renewed interest since it creates more motivation for improvement in rig performance which will result in reduced well costs. There are several different kinds of incentive type contracts in use today. Footage and turnkey contracts are the best known and are popular in many areas. When these kinds are not in the operator's and contractor's best interests, other types of contracts can still have a positive impact on the operations. Incentive Dayrate is one such contract. By making the operator's and contractor's objectives match, it creates a new team spirit between all the parties involved and allows the contractor to provide a better quality service. SEDCO FOREX experience shows that well operations are completed safely and more efficiently.
Driveability Performance Analysis of Threaded Connectors for Conductor Casing in Offshore Drilling
Authors: Milberger L. J. 
Published: December 2007

Abstract
This paper introduces a unique new system to quantify the driveability and strength of mechanical connectors for conductor casing that are subjected to the action of a pile driving hammer. The rating criteria, presented in terms of allowable pipe stress, are supported by extensive pile driving tests in which instruments located above and below the connectors measured the force-vs.-time and velocity-vs.-time characteristics of the stress wave traveling through the joint. Material qualification tests are also presented to demonstrate the desirable properties of materials suitable for driveable connectors.
Hang Casing Right and Reduce Failures
Authors: O’Brien T. B. 
Published: December 2007

ABSTRACT
At least 25 years ago an API study group in the Mid Continent recommended casing should be landed as cemented. API RP 5C 1 recommends the same thing today. Numerous papers in the interim recommend the same thing with some showing the need for added tension. Yet many operators/contractors consider slacking off 20-50% of pipe weight to be standard practice. Numerous casing failures are traceable to the practice of slacking off weight. Proper hanging practice can eliminate most of such failure.
Drilling Engineering Considerations in Designing a Shallow, Horizontal Well at Norman Wells, N.W.T., Canada
Authors: Markle R. D. 
Published: December 2007

Abstract
Unique engineering problems are encountered when designing shallow, long displacement horizontal wells. For a recent well of this description drilled in a remote northern location, the major engineering tasks identified in well planning were: 1) manage the impact of wellbore torque and drag to meet drilling objectives, 2) produce a high quality cemented wellbore capable of long term oil production, and 3) obtain high quality geological information to better define reservoir characteristics at the reef boundaries. This paper discusses how these specific issues were engineered for the drilling program.
Lost Circulation Challenges: Drilling Thick Carbonate Gas Reservoir, Natuna D-Alpha Block
Authors: Bell R. J. , Davis J. M. 
Published: December 2007

ABSTRACT
The L-Structure in the Natuna D-Alpha Block of the East Natuna Basin is located in the Natuna Sea in Indonesian waters, northwest of Kalimantan. The structure is a large structural stratigraphic hydrocarbon trap and is unique in areal extent and reservoir thickness among the various carbonate traps which are present in many southeast Asian basins. The porous reef complex (Terumbu formation) has a fairly homogeneous gas column 5,200 feet thick with CO2 content averaging 72%. The purpose of this report is to summarize the exploration drilling problems in the reservoir relating to severe lost circulation occurrences and to explain the steps which have been taken to alleviate these problems.
The thick Terumbu reservoir is a fractured, vuggy limestone. Furthermore, the long gas column in the reservoir presents a pore pressure profile which ranges from abnormally high in the top, down to a fresh water gradient in the bottom. The above factors compound the task of dealing with lost circulation and lead to additional drilling problems. Much progress has been made in reducing the severity of lost circulation and lessening its effects on drilling operations. Careful casing seat selection, improved drilling practices, strict control of drilling mud properties and use of lost circulation material in the mud while drilling have been major contributors to successful penetration of the entire reservoir.
Bit Performance and Selection: A Novel Approach
Authors: Farrelly M. , Rabia H. 
Published: December 2007

ABSTRACT
Much research has been dedicated to a better understanding of the factors involved in the drilling process. Equations are becoming more and more complex and require numerous empirically derived constants to be effective. An equation is presented here that relies upon the well-proven specific energy analysis of rock cutting. The equation used is simple, easy to apply to field drilling data studies and can easily be correlated from well to well. Although containing one empirical constant the authors have found this to be of minor importance.
The specific energy equation is applied to three wells in the North Sea, where detailed drilling parameter data were available. Specific energy is shown to indicate lithology changes and correct bit selections based on drilling performance. The specific energy approach to bit selection is not intended to be used entirely on its own, but in conjunction with more normal bit selection aids, such as the study of past offset bit records and cost per foot.
A Comparative Analysis of Efficiency and Horsepower Between Progressing Cavity Pumps and Plunger Pumps
Authors: Saveth K. J. , Klein S. T. , Fisher K. B. 
Published: December 2007

ABSTRACT
In selecting production equipment for a given well, the highest efficiency and the lowest required horsepower is the ideal situation. The progressing cavity pumping system is more efficient and requires less horsepower than the plunger pumping system at 150 BPD and 500 BPD from 2000 feet and 4000 feet respectively.
Jarring Effects on Retrievable Gas Lift Equipment
Authors: Barker L. D. , Hathcock L. A. 
Published: December 2007

ABSTRACT
Gas lift equipment problems such as inconsistent valve performance, leaking valves, and bent/broken latches occasionally occur. To quantify the effects of jarring on valve opening pressure, leakage, and latch deflection, simulated field testing was performed on 1 in. pressure operated gas lift valves, BK-2 style latches, and associated wireline tools. The testing was done in 2-7/8 in. and in. side pocket injection mandrels positioned both vertically and at a 45° angle.
Jar-down testing simulated the setting of a valve in the mandrel pocket. During the jarring sequence, new thoroughly aged valves exhibited fairly consistent opening pressures (average variance 0.7%), but usually leaked as the pressure was bled off. Used valves that had been disassembled, cleaned, and functionally tested exhibited large opening pressure changes and also leaked significantly during jarring.
Jar-up testing simulated the retrieval of a valve lodged in a mandrel pocket. Orienting kickover tools from two manufacturers were used in a 412 in. mandrel. New BK-2 style latches made of 17-4 PH material deflected more than 0.200 in. (5.1 mm), but exhibited no significant damage.
The Effect of Perforating on the Performance of Shale-Laminated and Crossbedded Formations
Authors: Ichara M. J. , Cannon D. E. 
Published: December 2007

ABSTRACT
The productivity of a completed well depends, to some extent, on the internal structure of the formation. This internal structure includes shale laminations and current beds of crossbedded units. In order to drill to "target" formations, hundreds of feet of laminated and crossbedded formations are traversed. Optimal shot density distribution is essential for completing these laminated formations. Too low a shot density limits production; too high a shot density wastes money and can cause casing damage. Tailoring the perforating to the minimum number of shots for optimum flow will improve the well's economics.
This study used a general-purpose finite-element program to simulate perforated, shale-laminated, and crossbedded formations.
A field example was used to investigate the effect of perforating on the performance of shale-laminated formations. The results show that 1) at high shot density, the performance of a laminated formation is practically independent of perforation location; 2) at low shot density, shale/sand distribution controls the performance of shale-laminated formations; 3) the performance of crossbedded formations is not a function of the dip angle of the foreset laminae but is a strong function of perforation length, with the perforation intercepting the laminae.
A shale distribution index has been defined and correlated with the productivity ratio of laminated formations. This correlation can be generated for a key well in the reservoir and the results can be used for optimal shot density selection for completion of the key well and other wells in the same reservoir.
A summary of recommendations for completing various formations, based on the results of this study and those of other investigators, is presented.
Application of Primary Cementing Principles, Rocky Mountains and Texas
Authors: Smink D. E. , Kundert D. P. , Vacca H. L. 
Published: December 2007

ABSTRACT
A review of 23 primary cementing jobs performed over an 11-year period in four states has shown that success is improved When attention is directed to low-cost means of improving displacement of drilling muds by cement slurries. The most important factors appear to be placement of centralizers and scratches, conditioning of the drilling mud, and pipe movement (reciprocation) while conditioning mud and while placing cement. Confidence gained in the use of these methods has resulted in a job technique wherein the top cementing plug is pumped down with 10% acetic acid or other desired perforating fluid followed by 2% KCl water. This technique permits lower cost completions.
The theory and application of cement bond logging are reviewed. Five example CBL-VDL logs are presented and discussed. Several examples are shown under applied surface pressure conditions. An example of a CBL-VDL log of an offset well where the principles of primary cementing were not observed is shown for comparison.
Curable Resin-Coated Sand Controls Proppant Flowback
Authors: Pope C. D. , Wiles T. J. , Pierce B. R. 
Published: December 2007

ABSTRACT
A study of fracture stimulations in two South Texas oil fields indicated that proppant flowback was a major problem. This paper examines thirty-four stimulations that used 100% sand as the proppant and thirty-five stimulations that used a tail-in of resin coated sand.
In the Big Wells Field, thirty-one wells have been fracture stimulated using 100% sand as the proppant. These wells averaged 1.25 failures per well per year. In the North Government Wells Field, three wells have been fracture stimulated using 100% sand as the proppant. These wells averaged 5.40 failures per well per year.
In order to reduce the incidence of proppant flowback while maintaining a high sand concentration, curable resin coated sand was substituted for the final 10-20% of the recommended amount of sand in the fracture stimulation. Once this resin coated sand is pumped into the fracture, it chemically bonds together to form a barrier against proppant flowback. In the Big Wells Field, thirty-one wells have been fracture stimulated using a tail-in of resin coated sand. These wells averaged 0.19 failures per well per year. In the North Government Wells Field, four wells have been fracture stimulated using a tail-in of resin coated sand. These wells have averaged 2.43 failures per well per year.
Characteristics of wells with proppant flowback were examined with respect to bottomhole pressure, waterflood response, and acid stimulation. A comparison was made between wells stimulated with 100% sand and wells stimulated with a tail-in of resin coated sand using decline curves and post fracture stimulation bottomhole pressure buildups.
Based on the results of these sixty-nine fracture stimulations, it can be concluded that a tail-in of resin coated sand is an effective method of controlling proppant flowback following fracture stimulation.
Temperature Data from Cement Interval Extremities Give Reduced WOC Time
Authors: Sykes R. L. , Stehle D. E. , Venditto J. J. 
Published: December 2007

ABSTRACT
A more realistic and better engineered cement slurry can be designed when bottomhole and top-of-cement (TOC) temperatures are known. These data can be obtained by running temperature recorders in the drill string during the clean-up trip, with one recorder at the bottom (TD) and one at the anticipated TOC. This configuration shows the actual temperature changes that the cement will experience. By noting the circulating rates during the temperature gauge run, the time to reach these temperature extremes can be calculated.
Laboratory tests can be modified to reflect these temperature extremes and heat-up rates to yield a more realistic cement design. The use of this modified testing procedure can result in lesser concentrations of retarder, better early compressive strengths at the TOC, and reduced WOC (waiting-on-cement) time.
This paper presents details of procedures used to (1) obtain temperature readings, (2) calculate heat-up rates for cement testing, (3) test optimum slurries, and (A) conduct cement jobs utilizing the optimized slurry.
Laboratory test data are presented showing (1) reduced retarder concentrations obtained by utilizing this modified test schedule, (2) better early compressive strengths at the top-of-cement, and (3) comparison of modified test results to standard API test results.
Field results showing WOC times and bond logs are presented.
Supervisory Control of Beam Pumping Wells
Authors: Dunham C. L. 
Published: December 2007

ABSTRACT
Close monitoring and control can greatly improve the effectiveness and economy of beam pumping operations, especially in oil fields with large numbers of wells.
Shell Oil Company has developed an oil-field supervisory control system for centralized computer monitoring and control of beam pumping wells equipped with microprocessor-based pump-off controllers.
This paper reviews the history of computerized beam pump monitoring and control in Shell, describes the capabilities of Shell's current system for supervisory control of beam pumping wells, discusses the operating and maintenance requirements for such a system to be successful, and reviews the benefits which are often realized.
Real Time Decision-Making through Use of a Log/Log Plot During a Frac Job
Authors: Jopling M. W. , Ketcher N. W. 
Published: December 2007

ABSTRACT
Since the publication of the paper by Kenneth G. Nolte and Michael B. Smith, "Interpretation of Fracturing Pressures" (September, 1981, JPT), more attention has been given to the meaning of pressure changes during fracturing treatments. Initially, log/log plots were made by hand, which usually did not allow sufficient time to make decisions affecting the job. In recent years, the major stimulation companies have introduced, into the field, treatment monitoring vans which have the capability to make real-time log/log plots of net pressure above closure vs. time. With the continuous plotter, the field supervisor can observe slope changes indicating lateral extension, height growth, excessive fluid leak-off, width growth or screenout conditions and have tine to make changes in job design as the situation requires.
In this paper, an example is given in which a screenout was avoided through use of the real-time log/log plot (Nolte-Smith plot). The log/log plot began indicating a screenout before the surface treating pressure had significantly increased. This was due to a higher density sand concentration being pumped down the tubing.
The ability of the treatment monitoring van (TMV) to sample data every 2 seconds and to display the data (both measured and calculated) every 10 seconds on a TV monitor, allows the field supervisor to visually follow the progress of the job. Western's TMV displays the data in 4 formats: TV monitors (2), x-y bed plotter, digital printout, and continuous strip chart. The TV monitors may be used to display total job and log/log plot, segmented job and total job, one parameter and total job or any combination as required by the field supervisor or engineer. The raw data, stored on two discs, is available for post-frac analysis if needed.
Although the Nolte-Smith1 technique for predicting screenouts requires a "dead string" pressure input, it is possible, by careful use, to utilize the computer to measure, record, calculate and display data for use as an on-site decision-making tool.
Combining Transient Rate and Pressure Data with Production Logging for Enhanced Well Test Analysis
Authors: Bingle C. F. 
Published: December 2007

ABSTRACT
Many gas wells drilled today are completed over 100 ft or more of gross pay interval to maximize deliverability, reserves, and revenue. Formation permeability of these wells is usually very low (less than 1 md). Use of conventional transient pressure analysis to understand formation properties is seldom done because of time (many days or even weeks) needed to acquire correct answers. Knowledge of producing zones and their respective amounts are rarely studied. Such limited knowledge concerning formation properties (permeability, pressure, drive mechanism, etc.) and flow profiles can often lead to poor reservoir management throughout the life of the field and eventually leave many thousands of dollars of reserves behind.
Combining production logging with the transient rate and pressure analysis (TRAP*) allows one to identify the wellbore's flow profile and formation flow properties such as permeability, average reservoir pressure, and skin factor (near wellbore and total skin) in less than one day. Such combination testing can identify flow regime, drive mechanism, coning or fingering problems, unusual pressure or zonal depletion, presence of crossflow, scale, or plugged perforations; all of which if identified in time, can be used positively to maximize production and revenue.
The TRAP technique uses the production logging tool. First, up and down passes over the perforated interval are made prior to the well test to identify the well's flow profile. Production logging passes made at varying flow rates can further be used to identify the reservoir flow behavior, and the associated reason. For the well test part, the TRAP technique incorporates measuring changing rate data with the corresponding pressure data during a buildup, drawdown, or multirate test. Using the principle of superposition (continual integral), it eliminates wellbore storage problems and identifies formation flow properties in a very short time frame.
The TRAP technique is illustrated through the analysis of two deep gas well tests.
Pressure Transient Analysis of CO2 and Enriched-Gas Injection and Production Wells
Authors: MacAllister D. J. 
Published: December 2007

ABSTRACT
A theoretical basis for pressure transient analysis of gas wells with emphasis on the real gas pseudo pressure approach is outlined. An analysis procedure is developed to analyze wells either injecting or producing predominantly CO2 or enriched gas. This procedure is used to calculate flow capacities and skin factors from pressure transient tests in injection and production wells from two CO2 projects. A computer program is documented which aids in the analysis of gas wells with the real gas pseudo pressure. Finally, example calculations are shown for a CO2 well, an enriched gas well, and an enriched gas well contaminated with CO2 / H2S.