bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experience With Effective Drilling
Authors: Remson D. R. 
Published: December 2007

ABSTRACT
Market conditions have established the importance of service quality as the standard by which drilling contractors must compete. Offshore drilling is a cooperative effort in which about 35% of the on-site time involves work tasks that are under the exclusive control of the drilling contractor, and most of the other 65% require his direct involvement to some extent. The way most drilling contracts are structured, the operator actually underwrites the Contractor's performance and thus has every right to expect some sort of service quality guarantee.
When based on timely and accurate data, planning and coordinationapplied to drilling a well can save significant amounts of time and money. They produce not only quicker results but also safer and morepredictable results. This paper presents the experience gained froma program applied to an international fleet of 11 jackup and 2 semi-submersible rigs over a three-year period, 1984 through 1986. Annualincreases in drilling efficiency of 3% were common, predictability was accurate to 97%, overall performance was enhanced during a period of low utilization and falling dayrates.
Development and Implementation of a Universal Subsea Wellhead System
Authors: Dykes C. E. , Hopper H. P. , Jones R. G. 
Published: December 2007

ABSTRACT
The use of exploration and appraisal wells in the development of offshore fields is essential in areas where the majority of new discoveries are likely to be classified as marginal. The initial selection of subsea wellhead equipment can dictate the viability of utilising the well at a later stage. Standardisation and completion flexibility must be incorporated into the specification of subsea wellheads. The paper discusses how this has been achieved by one major operator through the specification of a universal subsea wellhead system.
Drilling With Oil-Based Muds on Offshore Wells: Drilling Contractor's Viewpoint
Authors: Collings B. J. , Stone W. M. 
Published: December 2007

Abstract
While environmental constraints have lessened the desire or will to drill with oil-based muds on offshore wells, the fact remains that use of this type of drilling fluid is an economically sound practice on some wells. Some troublesome shales make it the only way to reach the objective. Unfortunately, the decision to use oil-based mud comes when several attempts, with water-based muds, have failed. Lost hole, lost bottom hole assemblies, and lost MWD equipment result in extremely high well costs for the operator.
When the decision to use oil-based muds does come, the drilling contractor's charge is get the rig to a zero discharge capability, arrange surface equipment, and develop procedures and training for the crews so that drilling with this system is at maximum safety and efficiency. The problem becomes more complex on floaters. The position of the blowout preventers and the difficulty of detecting small gas influxes have created the potential hazard of sudden unloading of the riser before diversion can be accomplished. Surface equipment on most rigs only provides for diverting the flow overboard or taking the surge of mud and gas into the shaker room. Both of these provisions leave much to be desired!
The drilling contractor can improve the situation by attacking the problem with a five step program. This program involves: Pre-planning with the operator to circulate suspected, but undetected gas influxes with positive control.Build a better flow line gas discharge system.Install a better firefighting system in the mud pit room.Install a bleeder valve arrangement to help vent the stack.Crew training on the procedures used in safely handling an oil mud drilling program.
The Planning and Drilling of the World's First Horizontal Well From a Semisubmersible Rig
Authors: Clark A. C. , Cocking D. A. 
Published: December 2007

ABSTRACT
The Cyrus field located in Block 16/28 of the UKCS was discovered in 1979. After appraisal drilling, indications were that conventional wells would not be sufficiently productive to make the field commercial. Therefore, a horizontal well development programme was investigated.
All aspects of horizontal drilling were addressed, in particular those that would allow the bit to be steered to the horizontal from a floating rig. State of the art technology in the form of a drill string simulator was utilised to develop the well trajectories. As the simulator had shown great accuracy on field trials, it allowed the optimum profile to be selected with confidence.
The first well was spudded in June 1988 and drilled 565 m (1854 ft) of horizontal hole through the main producing interval. This paper addresses the main aspects of the planning and drilling of the world's first horizontal well drilled from a semi-submersible rig.
Improved Pressure-Volume Schedules for Circulating Out Kicks in Directional Wells
Authors: Cheatham C. A. 
Published: December 2007

ABSTRACT
While circulating out kicks in directional wells, an industry-accepted practice implicitly assumes that the entire wellbore is slanted at a constant angle. For wells with hole inclinations less than thirty degrees, this assumption is appropriate since the resulting error is small. In highly deviated wells, additional overbalance incurred by neglecting the actual well path can be large enough to cause lost circulation and/or stuck pipe. A method is presented to correct this error for any directional well. Guidelines are given for the common case of build and hold wells.
Casing Point Selection at Shallow Depth
Authors: Aadnoy B. S. , Soteland T. , Elligsen B. 
Published: December 2007

ABSTRACT
Different oil companies place shallow casing strings at different depths. Apparently there is no general method or procedure that gives the optimum location. This paper is an attempt to define this optimum casing seat location. Potential benefits are improved safety and economy of the operation.
Two main factors determine the depth of the casing shoe, namely the fracture pressure and the pore pressure. A third factor is lithology, since it is desirable to place the casing shoe in a competent shale section. Methods to predict fracture gradients for deeper wells already exist. In this paper a method to predict fracture gradients for shallow wells is derived. This method is combined with kick tolerance criteria to yield a casing depth selection method. Also, the variation in fracture pressures at any depth is investigated.
A case study of a field offshore Norway is performed. The preliminary conclusions are that the 30 in. casing setting depth is difficult to model, while the 20 in. casing string could be set at shallower depths. The large spread in leak-off pressures of the field is further investigated. Some of the spread is found to be caused by the failure mechanisms of the rock, and is therefore unpredictable. However, part of the spread in observed fracture gradients seems to correlate with mud properties. Improved hole strength is therefore possible by building a proper mud.
Simulation of a Naturally Fractured Reservoir, Point Arguello Field, Offshore California
Authors: Van Bloemen Waanders B. G. , Litvak B. L. 
Published: December 2007

ABSTRACT
A computer simulation methodology is presented to help direct development of the Point Arguello Field, California Offshore, Santa Maria Area. The Monterey producing formation is naturally fractured and exhibits extreme lithological variation both vertically and horizontally. The fluid-flow characteristics are extremely complex and present many challenges to reservoir management. As part of a continuously evolving process, the initial phase of this simulation project consists of calibrating a double-porosity model with quality data interpretation results and to do so without benefit of production history. Pressure-transient test results dominate the major portion of the model calibration process, although results from logging, coring, and fluid analyses were also used. Various reservoir-parameter sensitivities were studied to determine the effects of the dominating characteristics on production forecasting. The objectives of the sensitivity studies consisted of the determination of optimum development strategies such as evaluating the need for infill drilling and selecting correct perforating intervals. Production forecasts were generated to compare different development scenarios, and, based on these forecasts, development directions were provided for the Point Arguello Field.
An Interporosity Flow Model for Naturally Fractured Reservoirs
Authors: Jalali Y. , Belani A. , Fujiwara K. 
Published: December 2007

ABSTRACT
The producing capacity of a naturally fractured reservoir is governed by interporosity flow since most of the fluid resides in the rock matrix. A distributed formulation is introduced to account for variability in the strength of interporosity flow across the reservoir. The model can account for deterioration or enhancement of reservoir producibility resulting from development of interporosity skin and closure of fractures or hydraulic fracturing and acidizing. This formulation suggests a reason why certain naturally fractured reservoirs do not experience sudden rate decline as predicted by classical double porosity models.
Evaluation of Oily Waste Injection Below the Permafrost in Prudhoe Bay Field
Authors: Abou-Sayed A. S. , Andrews D. E. , Buhidma I. M. 
Published: December 2007

ABSTRACT
This paper presents the results of an extensive study and field test carried out at the site of Prudhoe Bay's four oily waste injection wells. The field work was part of an overall environmental assessment intended to: (1) confirm earlier results indicating that no fluid communication was occurring with the permafrost; (2) determine optimum conditions for the disposal of waste in the presence of hydraulically-induced fractures; (3) substantiate that an increased injection pressure could be safely implemented. A three day injection test, including a step-rate stage, was carried out. Data collected included surface and downhole pressures, in-si tu stress measurements, and monitoring of ground surface deflections and wellbore hydraulic impedance.
Radially symmetric surface tilt patterns showed that the test well connects to a horizontal fracture of 60-foot radius. Wellbore impedance indicated that a horizontal fracture with 9-18 foot radius communicated with the well. Integration of rock mechanics, historical information, and the collected data provided a clear picture of what was occurring underground. The different evaluation techniques showed consistent results as reflected in the estimated fracture size, placement and damage zone properties.
Evaluation of a Complex Sandstone Reservoir for EOR
Authors: Pathak P. , Kuch K. D. , Kriel B. G. , Pasternack E. S. , Moorefield T. P. , Ligon J. H. , Salter S. J. 
Published: December 2007

ABSTRACT
A methodology for evaluating a complex reservoir for an EOR process is presented in this paper. In this methodology, two factors are emphasized. First, utilization of a stagewise workplan with numerous go / no-go decision points is shown to be important in avoiding the expenditure of significant time and money in the application of an EOR process to an inappropriate reservoir. Second, the importance of a multi-disciplinary workteam is emphasized. The tasks required to carry out such a reservoir evaluation involve diverse knowledge and skills beyond the ability of any one discipline. Finally, the workplan must be tailored to the specific needs, or characteristics, of the reservoir.
In this paper, we evaluate the South Cuyama Field for the application of Micellar-Polymer Flooding. The South Cuyama reservoir is a mature field in California that has both complex geology and a complex operational history. Two factors were found to be critical in determining the viability of the micellar process in South Cuyama. First, the faulted nature of the South Cuyama sands emphasized the importance of sand continuity between injectors and producers. Second, in order to make the EOR process profitable, the remaining oil in South Cuyama had to be large enough to justify the added expense of process implementation.
This paper presents the results of a multi-disciplinary study by engineers, geologists and geophysicists from the Research, Engineering, and Operations organizations. This study starts with preliminary reservoir screening based on average reservoir properties, progresses through the reanalysis of existing data to acquire an updated picture of the reservoir and determine the key questions to be answered, describes a joint geological / geophysical study which included a 3D, high-resolution seismic study, reports the results of field work done in existing wells, presents the results of updated material balance and volumetric studies, and describes the drilling and coring of a reservoir delineation well along with the analysis of the core. Particular emphasis is placed on determining the amount and distribution of remaining oil saturation, which is studied by log-inject-iog tests, single-well tracer tests, laboratory core analysis, reservoir performance, and OOIP studies. The progression of the workplan is in the order of increasing effort and expense. As key questions are identified and critical data found lacking, we progressed logically to the next step. The results of this study show that South Cuyama is not a good candidate for micellar-polymer flooding. Using the methodology presented here, we were able to determine this fact without actually running a pilot test, thereby saving considerable expense.
Use of Downhole Pulsation Dampener To Eliminate the Effect of Fluid Inertia on a Rod Pump System
Authors: Svinos J. G. 
Published: December 2007

ABSTRACT
Fluid inertia effects increase equipment loading and reduce efficiency in high rate shallow wells with very low gas production (producing more than 800 BPD from depths of less than 2,500 feet). In deeper wells this effect is negligible. However, in shallow, high rate rod pump wells that are primarily found in California, fluid inertia is one of the dominant factors affecting system loading and performance. This effect is one of the main reasons most design methods for rod pump systems do not agree with field measurements for shallow wells.
In an attempt to reduce the damaging effects of fluid inertia, a prototype of a downhole pulsation dampener was successfully field tested in a California well with severe fluid inertia effects. As Figure 1 shows, the device consists of a perforated pup joint of tubing covered by a Kevlar reinforced elastomeric bladder. This assembly is enclosed in a sealed steel outer housing. The volume between the bladder and the housing is pre-charged with nitrogen to a pressure equal to the tubing pressure at the point of installation. For the test, the dampener was installed as the first joint of tubing above the pump.
The device operates as follows: On the upstroke, as the traveling valve closes, the plunger picks up the fluid load and accelerates it creating a pressure pulse. The dampener absorbs this pulse as bladder expansion compresses the nitrogen. On the downstroke, as the pressure in the tubing drops, the bladder returns to its original position.
The downhole pulsation dampener completely removed the fluid inertia effects. Dynamometer cards showed a dramatic difference in shape between the "before" and "after" cases. Dynamometer analyses for before and after dampener installation show the device was effective in reducing gearbox loading by 36 percent, sucker rod loading by 22 percent and polished rod horsepower by 20 percent. Fluid level and production rate remained approximately the same.
Simulation of the Bishop Steam Foam Pilot
Authors: Patzek T. W. , Myhill N. A. 
Published: December 2007

ABSTRACT
In this paper we present a simple model of steam foam transport and apply it to the Shell Kern River Bishop pilot. The only adjustable parameter in the model is an effective surfactant partition coefficient that accounts for surfactant losses and inefficiencies of foam generation, and determines foam propagation rate. Once this partition coefficient is calibrated to match observed foam growth in the pilots, the simulator correctly predicts an incremental 5.5 percent OOIP recovery due to steam foam and additional 3 percent OOIP due to infill wells.
"What-if" simulations using an "enhanced" steam foam (twice as strong as AOS-1618, propagates 20 percent faster and reduces ROS by 7 percent) show a dramatic increase in incremental oil recovery (17 versus 5.5 percent OOIP in the Bishop pilot) and a dramatic reduction in surfactant requirement (5 versus 15 lbs AOS/Bbl incremental oil).
Comparison of HASDrive and Sand-Filled Multiple Communications Steam Recovery Processes for Heavy and Extra-Heavy Oil Reservoirs
Authors: Toma P. , Reitman V. , Coates R. M. , Heidrick T. , Ridley R. K. 
Published: December 2007

ABSTRACT
An assessment of two novel, steamdrive recovery processes for heavy oil reservoirs is presented.
Special experimental procedures were designed and used to assess and compare steamdrive recovery processes using a HAS-pipe or a sand-filled channel (SFMC) in a simulated tar sand field. It was found that temperature development and distribution of saturation progress more uniformly around the HAS-pipe than around the sand-filled channel, and this could explain higher initial recovery rates observed for SFMC than for the HASDrive process. A multicomponent thermal numerical model was first validated against laboratory experiments and was then used to assess the influence of reservoir properties such as formation depth and oil viscosity, on recovery processes employing either (SFMC) or HASDrive-hot pipe strategies.
The effectiveness of each process was assessed using the final recovery and diagrams of the key characteristics of oil-steam ratio versus running time.
The results indicate that for shallow heavy oil reservoirs the HASDrive process can be more effective than the SFMC process. The situation is reversed for higher permeabilities and deeper formations, where a better chance of effectively recovering the viscous oil is indicated for the SFMC process.
A new steamdrive recovery process employing a HAS-pipe embedded in a sand channel is suggested for shallow heavy oil formations. This process was analyzed and compared to both the SFMC and HASDrive recovery processes.
Wellbore Drillstring Mechanical and Hydraulic Interaction
Authors: Saleh S. T. , Mitchell B. J. 
Published: December 2007

ABSTRACT
Hole enlargement is a common problem encountered in drilling practices. It is the purpose of this paper to address the effect of hydraulic and mechanical forces acting on the wall of the wellbore. Field data from the Williston Basin (caliper logs, bit records, mud recap sheets) were used in correlating the effect of various hydraulic and/or mechanical parameters versus hole enlargement. In addition, the paper describes analytical techniques for the determination of hydraulic and/or mechanical forces created by the drill string and/or the movement of the drilling fluid.
The investigated hydraulic parameters are the annular flow regime, annular pressure losses, mud rheology, jet impact force, surge pressure, and the hydraulic effect of rotating and orbiting drill string. The power law model was used to calculate annular pressure losses and Reynold's number. Hydraulic forces created by the rotation of the drill string were computed with classical rotational viscometer model.
Mechanical forces of the drill string acting on the borehole wall were investigated below and above the neutral point of bending. Two types of holes were studied: straight and vertical holes, and vertical and doglegged holes.
Analysis with the author's model shows that the inertial force causes the drill pipe to contact the wellbore between the tool joints, and the corresponding contact forces was determined as a function well depth.
Multiphase Well Test Analysis: Pressure and Pressure-Squared Methods
Authors: Al-Khalifa A. J. , Horne R. N. , Aziz K. 
Published: December 2007

ABSTRACT
There are two practical approaches to analyze multiphase well tests. These are the pressure and the pressure squared methods. This paper investigates the limits of these methods as they apply to different reservoir and testing conditions.
The pressure squared approach is applicable to systems in which a gas phase is present (i.e. gas-oil and gas-oil-water systems), while the pressure approach is superior for application in oil-water systems.
Unlike the pressure squared approach, the pressure approach is found to be rate sensitive and only applies at low flowing rates. The higher the flow rate, the greater the underestimation of the individual and total system mobilities. For some cases, the pressure semilog plot does not exhibit any straight line; while for other cases it shows two straight lines which may be misinterpreted as an indication of a composite system. This sensitivity to rate is due to the assumptions involved in deriving the pressure diffusivity equation and the improper linearization of the inner boundary condition. On the other hand, the pressure squared approach is insensitive to rate because of the proper linearization of the inner boundary condition and the better treatment of the nonlinear terms when deriving the diffusivity equation in terms of p2.
This paper also discusses the rate normalization of multiphase well tests with varying flow rates, i.e. buildup tests dominated by afterflow, and drawdown tests dominated by unloading effects. The rate normalization, currently used in the industry, is based on the pressure approach which requires that the total rate in RB/D be monitored throughout the test. This is not easily done in practice. Furthermore, this normalization results in underestimated values of total system mobility and yields no individual phase permeability. This paper proposes a new rate normalization method based on the pressure squared approach. The proposed normalization requires only surface oil rates to be monitored. Moreover, it results in reasonable estimates of individual phase permeabilities and thereby an accurate value of total system mobility. A simulated example which demonstrates the applicability of this proposed normalization is presented.
An Analytical Cyclic Steam Stimulation Model for Heavy Oil Reservoirs
Authors: Gozde S. , Chhina H. S. , Best D. A. 
Published: December 2007

ABSTRACT
The cyclic steam stimulation of wells is of great interest in thermal recovery projects, especially in heavy oil reservoirs where steam injectivity can be achieved without hydraulic fracturing.
A number of analytical steam stimulation models have been developed in the past, but no one model can be used for a wide variety of heavy oil reservoirs (i.e. pressure depleted, pressure drive, primary production). A new analytical model for cyclic stimulation of heavy oil reservoirs, which includes pressure drive, has been developed. The model incorporates some of the major recovery mechanisms which are applicable for steam stimulation (i.e. pressure drive, gravity drainage, cold oil influx, relative permeability effects). Simple analytical equations are used to account for the energy and material balance calculations. The model is applicable to both immobile and mobile oil at original reservoir temperatures. The proposed model is a modification and extension of the Gontijo & Aziz model and has additional features beyond the Gozde-AOSTRA model, which include heat loss calculation and wellbore heat losses.
The model is validated through a comparison of the results with available field data. A comparison with another analytical model showed that the proposed model is much better equipped to history match a wide variety of heavy oil reservoirs.