bluuebunny/crossref_metadata_2025_split huggingface dataset:
Probabilistic Performance of Non-Conventional Wells in Deep Water and Amazon Jungle Fields in Brazil
Authors: Padua K.G.O. 
Published: December 2007

Abstract
Non-conventional wells such as horizontal, highly deviated and multilateral wells are becoming more and more common. Their customary advantages over conventional wells are usually demonstrated based on the deterministic comparison of their production and economic forecast.
However, uncertainties about reservoir (size, permeability, porosity, etc), well characteristics (length, radius, etc) and operational factors (wellbore pressure, damage, etc) yield in fact a probabilistic distribution of production and economic forecast which only on average is approximately represented by the deterministic approach.
This paper presents the development and application of a mathematical and computational model which accounts for the above uncertainties and yields a probabilistic function of the production and economic advantage on using non- conventional wells over conventional wells.
The production and economic forecast is based on simplified analytical solutions such as productivity index and decline curve. Uncertainty is accounted by means of Monte Carlo simulation based on probabilistic distribution function.
The model has been applied in potential areas in Brazil for screening purposes and has helped ranking prospects on the basis of their appropriate risks/rewards. The results show a probabilistic distribution of productivity improvement which compares satisfactorily with that presented by Beliveau.
The model has also been applied in areas partially developed with non-conventional wells for accounting prediction performance. Comparison with actual wells drilled in Brazil (more than 40) suggests a probabilistic distribution not fully developed, probably due to the small number of wells considered.
The overall results suggest that the performance expectation of non-conventional wells over conventional wells, because of the inherent uncertainty of the business, is also dependent on the number of wells drilled.
Technical contributions involve the development and application of a probabilistic approach to non-conventional production performance estimate which leads to better risk assessment and results evaluation.
P. 187
A Practical Method for Evaluating the Merit of Information
Authors: Enderlin Milton Bock 
Published: December 2007

Abstract
If reservoir evaluation is to reflect reality, then the information populating the models and simulators must be of highest possible merit. The merit of the input information foretells potential merit of the output. Therefore an evaluation of the input's merit can provide an insight into the potential validity of the modeling and simulation effort.
Information is derived from data by the application of knowledge. In complex exploration and development projects information evolves in a cyclic manner such that one person's information becomes another person's data. The record of data-to-information conversions from initial measurements to final information is a "chain of custody" or "audit trail." Without a "chain of custody", the associated information is without merit.
The merit of the final information is also strongly controlled by the merit of the initial measurement. Merit of initial measurement is a function of precision and a "traceable calibration" of accuracy. Both precision and accuracy must be known in order to have information of the highest merit. If an initial measurement lacks precision, then the derived final information is only predictive in nature. To assess the merit of predictive information, knowledge of a "history of predicted outcomes" is required.
This paper presents a practical approach for evaluating the merit of information by classifying it as high, medium, low, lowest, or without merit. "Chain of custody", precision, accuracy, and "history of predicted outcomes" are the discriminators. Application of this (or another similar) method will provide understanding of the output validity of the model and simulator, which will in turn measure the reservoir evaluation
P. 197
Proppant Transport Characterization of Hydraulic Fracturing Fluids using a High Pressure Simulator Integrated with a Fiber Optic/LED Vision System
Authors: Shah Subhash N. , Asadi Mahmoud , Lord David L. 
Published: December 2007

Abstract
Slurries of selected hydraulic fracturing fluids such as 40 lb/Mgal HPG linear gel and borate-crosslinked 35 lb/Mgal guar gel were evaluated to characterize their proppant transport properties using 6 ppg 20/40 mesh sand. In addition, fluids such as water, 40 lb/Mgal HPG linear gel, and borate-crosslinked 35 lb/Mgal gel were evaluated to determine their relative ability to remove the fluidized layer lying along the top of settling proppant bed and to subsequently erode the more compacted layers below.
The experimental study utilized a unique high pressure parallel plate flow cell, simulating a downhole fracture, integrated with a vision system of fiber optic and Light Emitting Diodes (LED). The vision system was used to quantify proppant transport characteristics and to study various aspects of proppant transport including bank buildup. Selected hydraulic fracturing slurries were pumped into a high-pressure flow cell having a 0.375" fracture gap width. The slurries were pumped through 3000 ft of 1.188 in. ID coiled tubing, 500 ft of 2 in. ID heat exchanger, and a 2.75 in. inlet manifold that could be configured to represent a wellbore having various perforation arrangements. Slurries were pumped for a selected time at a fixed shear rate in the range of 60 to 120 sec to observe the rate of bed sedimentation. These initial slurry injections were followed by various fluids and slurries to assess the degree of compaction within the previously deposited bed.
Data analysis indicates that slurry sedimentation in polymer solutions follows a non-linear relationship with time at a fixed shear rate and that perforation configuration affects proppant transport, bed height growth, and proppant bed wash off near the wellbore. It is also shown that bed height growth is not directly proportional to shear rate. Results from the current study also show that the fluidized layer along the top of the proppant bed is easily removed by a clean crosslinked gel. However, erosion of the more compact underlying layers was found to depend on a number of factors. Among these factors are the type of slurry which formed the deposit, the type of fluid or slurry being used in an attempt to erode the bed, and the total pumping time devoted to eroding the bed.
P. 253
Multipurpose Wells: Downhole Oil Water Separation in Your Future
Authors: Stuebinger Lon A. , Elphingstone Gerald M. 
Published: December 2007

Abstract
Promising new technologies that are being advanced have the potential to reshape development strategies in your fields. It is not always necessary to dedicate wells to production or injection; now, both functions can be performed within one multipurpose wellbore. Technologies exist to reduce water-handling volumes at the surface by keeping the water downhole.
The discovery of downhole oil, water, and gas gravity segregation in the wellbore and the ability to keep fluids separated makes it possible to generate revenue from a wellbore at the same time that it is injecting or disposing water. This paper will discuss:–Design and testing at the Rocky Mountain Oilfield Testing Center of the first Downhole Oil Water Separation (DOWS) artificial lift system to utilize downhole gravity segregation–Evolving modeling procedures–Superior environmental performance–Impediments to deploying radically new technologies–A vision of the future
P. 205
Field Trial of the First Desanding System for Downhole Oil/Water Separation in a Heavy-Oil Application
Authors: Danyluk T.L. , Chachula R.C. , Solanki S.C. 
Published: December 2007

Abstract
Many wells producing medium or heavy oil from unconsolidated sandstone reservoirs experience high water production while still at relatively low recoveries. Water production causes numerous operational problems leading to increased operating and capital expenditures for higher volume artificial lift systems and water handling facilities. The recent development of Downhole Oil/Water Separation (DHOWS) systems has provided operators with an alternative approach to contend with increased water production to improve recovery from these reservoirs.
PanCanadian Petroleum Ltd. has been an industry leader in the development and application of DHOWS technology, particularly with respect to its use in fields producing heavy oil. The use of DHOWS systems in such applications is complicated by the inherent production of sand with the viscous heavy oil. In the commercially available DHOWS systems, the solids that are produced tend to remain in the disposal water stream, which is reinjected downhole. Depending on the solids volume and well conditions, the solids may invade and plug the disposal zone or they may accumulate in the wellbore. In either case, these situations ultimately lead to a reduction in injectivity that reduces the effectiveness, or preclude the further use of a DHOWS system. This decline in injectivity has been observed in field trials with both progressing cavity pump (PCP) and electric submersible pump (ESP) DHOWS systems at PanCanadian's Hayter and Provost fields in northeastern Alberta, Canada (Figure 1). The accumulation of sand in the wellbore was confirmed during subsequent workovers.
PanCanadian enlisted C-FER Technologies Inc. to develop a desanding separator unit for use in conjunction with the commercially available DHOWS systems. A desanding separator unit was designed to remove solids from the produced fluids and to commingle them with the concentrate oil stream produced to surface by the DHOWS system. Following a feasibility study that examined several different design options, a prototype desanding separator was built. The functionality of the separator unit was confirmed through controlled laboratory tests and the unit was subsequently tested in combination with a PCP-DHOWS system. 'The system was then installed in a PanCanadian well which had previously experienced injectivity problems with a DHOWS system. Initial results show that sand is being produced to surface and that the injectivity has remained relatively stable.
This paper describes the prototype system developed and presents the results of the field trial conducted by PanCanadian.
P. 225
Makarem-l Relief Well Planning and Drilling
Authors: Roes V.C. , Hartmann R.A. , Wright J.W. 
Published: December 2007

Abstract
This case history describes planning and execution of a deep relief well operation that resulted in re-entering, killing and abandoning a wellbore which was blowing in the subsurface. In 1994, a gas exploration well, Makarem, was sidetracked past a bottomhole assembly, which had become stuck almost 1,000m off bottom. A kick was subsequently taken, indicating charging of shallower horizons from a deep, sour, high-pressure gas reservoir at potentially high rates. Attempts to reenter the original wellbore while drilling ahead in the sidetrack hole were unsuccessful. The well was re-entered in 1997 with the objective of isolating the flowing zone to prevent potential environmental impact, future drilling problems, and the loss of hydrocarbon reserves resulting from uncontrolled flow of gas in the subsurface. This case history reviews planning and execution of a deep horning-in operation to locate and re-enter the 12 1/4" open hole below the bit of the stuck assembly, 3680m below surface. Key issues addressed during the planning phase included relief well strategy, positional uncertainty, well control scenarios, options for isolation and contingencies. An active electro-magnetic ranging technique was employed to successfully locate and track the target assembly to an eventual direct intersection with the crossflowing hole. Execution of the intersection plan is detailed, with emphasis on horning-in on the fish, borehole surveying techniques and quality assurance. Also covered is the operational organisation, and details of the activities following intersection, which included stabilisation, cleanout and abandonment of almost 1,000m of borehole which had been inaccessible for over 3 years.
P. 367
Mars Debottlenecking Project
Authors: Curole M.A. , Turley A.J. 
Published: December 2007

Abstract
The Mars installation consists of a four (4) block unit with a Tension Leg Platform (TLP) installed in Mississippi Canyon Block 807. The discovery well was drilled in 1989. Development studies were conducted in 1990 through 1992 with project fabrication funding occurring in the fall of 1993. A twenty-four (24) well dual casing riser TLP in 2,933 feet of water was approved. The facility was originally designed to process 100,000 BBL/D of oil and 110 MMSCF/D of gas. Maximum individual well rates were estimated at 11,000 BBL/D of oil. During the fabrication phase of the project in 1995, it became clear that completion technology advances had increased the individual well production potential far beyond the 11,000 BBL/D of oil benchmark, and the ultimate TLP production potential would exceed the topsides nameplate capacity. A study was undertaken to debottleneck the topsides in order to handle unconstrained production rates. The study evaluated all phases of the production facility impacted by the increased production. This paper will present the evaluated phases of the production facility debottleneck, will sumarize the modifications to the facilities at the TLP integration site and will review the utilization of several new and innovative technologies. The facilities systems that were debottlenecked included:–Production High Rate Flowlines–Oil Treating–Compression Units–Dry Oil Sales Pumps–Utility Systems–Flare System–Gas Dehydration
P.265
Synergistic Value Optimization from Reservoir to Sales - A West Panhandle Gas Field Case History
Authors: Burgess Roy A. , Finch Clyde L. 
Published: December 2007

Abstract
Between 1993 and 1997, production from Conoco's West Panhandle Gas Field in Carson County, Texas was doubled from 20 to 40 MMCFPD. By 1993, reservoir pressure had fallen below 30 psig and production from the wells was at an all time low. The wells, many of which were drilled during the first half of the century, were showing signs of age and poor mechanical condition. In 1993, Conoco gained operational control of the gas gathering system and conducted a multi-well pilot that increased production from 300 to 1,250 MCFPD in a few months. The subsequent full-scale optimization of the 100,000 acre field involved working-over more than 100 wells, drilling replacement wells, installing electric vacuum compression on nearly 100 wells, erecting over 90 miles of high voltage power line, adding 6,400 HP total at five compressor stations and debottlenecking the gas gathering lines.
P. 303
A Method for Delumping the Results of a Compositional Reservoir Simulation
Authors: Leibovici Claude F. , Barker John W. , Wache David 
Published: December 2007

Abstract
A new method for delumping the results of a compositional reservoir simulation is presented. The method is based on a previously published algorithm for delumping the results of a single flash calculation. Results are presented for two cases: depletion of a volatile oil reservoir and depletion with lean gas reinjection. The compositions obtained by delumping the results of a 7-component reservoir simulation are compared with those obtained from a 16-component reservoir simulation. If there are no binary interaction coefficients, the agreement is almost exact, and the delumping takes only a fraction of the computation time of the 16-component simulation. When non-zero binary interaction coefficients are introduced, the accuracy of the method is slightly reduced. P. 339
Upscaling, Gridding, and Simulation Using Streamtubes
Authors: Portella Ricardo C.M. , Hewett Thomas A. 
Published: December 2007

Abstract
This paper presents an innovative upscaling methodology based on the semi-analytical simulator developed in the first part. The methodology generates a coarse grid based on streamtubes and isobars, whose upscaled properties are accurately calculated using the properties of each streamtube that constitutes the coarse block. Beyond the calculation of upscaled static properties of the grid, the methodology also calculates upscaled relative permeability curves, or pseudoflinctions, using the semi-analytical streamtube method to perform this without requiring any significant additional time. Tests showed that the results from the streamtube coarse grid had an excellent agreement with the fine grid solution. In contrast, simulations with a coarse grid upscaled with conventional techniques failed in many situations. Although this upscaling methodology is heavily based on a fixed streamtube simulaflon method, it provided good results even for situations in which this streamtube simulator is not supposed to work, such as displacements with favorable mobility ratios, and for problems with gravity and compressibility.
P. 361
Field Measurements of the Effects of Drillstring Velocity, Pump Speed, and Lost Circulation Material on Downhole Pressures
Authors: Clark R.K. , Fontenot J.E. 
Published: December 2007

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

Abstract
Detailed downhole pressure measurements were made in two wells to observe the effects of pipe velocity and circulating rate in weighted pipe velocity and circulating rate in weighted oil-base and water-base muds. The effects of lost circulation material on downhole pressures in the water-base mud were also measured. A major conclusion is that control of the instantaneous (rather than the average) pipe velocity while tripping and making connections is necessary to minimize pressure changes downhole.

Introduction
The control of downhole pressures while drilling is an essential part of well control. Changes in downhole pressure result from drill string movement, pump operation, and changes in mud rheology and density. The addition of certain types of lost circulation material to control mud losses can increase mud viscosity and downhole pressures and therefore can aggravate the lost circulation problem. Knowledge of the downhole pressure at all times is of great importance to the success of any drilling program.
In view of a lack of published data on downhole pressures in various phases of drilling operations, a program was initiated to measure downhole pressures as they are affected by circulation rate, pipe velocity, and the addition of lost circulation material. Detailed pressure measurements were made in two wells, pressure measurements were made in two wells, one in a weighted oil mud and one in a weighted water-base mud. The effect of lost circulation material was determined in the test with a water-base mud. This paper discusses the pressure data obtained and the conclusions pressure data obtained and the conclusions derived from the data.

Background
The importance in well control of downhole pressure changes caused by circulating the mud and moving the drill string has been recognized for some time. In 1934, Cannon measured swab pressures due to drill string movement, and in 1951, Goins reported measurements of surge pressures resulting from drill string movement. Graphic descriptions of these pressures were given by Cardwell and Clark. The last reported measurements of downhole pressure changes were those by Wilson in 1962. Burkhardt and Schuh have described analytical methods of calculating downhole pressure changes. The authors have recently pressure changes. The authors have recently described a new computer program for calculating swab/surge and circulating pressures.
The previous measurements of downhole pressure changes have been very limited in scope pressure changes have been very limited in scope and in instrumentation.
Extra Increments of Pressure or Mud Weight Safety Factors Added During Well Killing Procedures Can Be Unsafe
Authors: Kastor R.L. , Letbetter S.C. 
Published: December 2007

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

Introduction
It is common practice during drilling of a well to carry an overbalance or increment of md hydrostatic pressure greater than the anticipated formation pressure at any point in the hole to maintain primary control of the well. In addition, during the drilling operation this overbalance usually allows manipulation of the drillpipe without swabbing formation fluid into the hole, unless drillpipe motion is excessive. Common overbalance margins range from 300 to 500 psi, although in some areas wells have successfully been drilled with an underbalance. The commonly held concept is that an increment of hydrostatic pressure over the formation fluid pressure provides the safety factor that allows effective control over the well.
During well-killing procedures, however, these extra increments of pressure from mud weight may cause problems in well control. They may require the holding of extra backpressure on the casing annulus in order to maintain a constant bottom-hole pressure. As a result, in a well having a marginal fracture of breakdown pressure, it is possible that this extra pressure, it is possible that this extra pressure may result in fracturing the formation, pressure may result in fracturing the formation, which could ultimately result in losing control of the well.
It is believed this phenomenon could best be explained by the use of a series of examples that follow.

BASIC KILL PROCEDURE
At the present time, a great many operators agree that the safest well control procedure is the constant bottom-hole pressure method, which in turn infers maintaining a constant pump speed and, for the largest part of the kill procedure, maintaining a constant drillpipe pressure. Therefore, it will be assumed that the standard constant bottom-hole pressure technique is being utilized, and the examples will relate to this concept. Later, variations will be considered and discussed.
There are two basic methods for applying the constant bottom-hole pressure method of well control. The first of these, known as the "driller's" method involves first circulating out the well kick with the same mud weight used in drilling the well, and maintaining secondary control of the well by holding an annular backpressure. Subsequently, after the gas kick has been circulated from the well, the drilling mud is replaced with a higher mud weight sufficient to return to primary control of the well.