bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Approach for Matrix Acidizing of Water Injectors in Low-permeability Sandstone Fields
Authors: Wang Xugang , Zou Honglan , Cheng Xingsheng , Li Suzhen , Zhang Boping , Hill A. D. , Zhu D. 
Published: December 2007

Abstract
The goal of this study was to design a cost-effective matrix acidizing treatment to enhance the performance of water injection wells in a low permeability sandstone reservoir in China. The sandstone reservoir in the Western Field in China is ultra-deep, low permeability, and high temperature. The Eastern Field reservoirs are multi-layered and low permeability. Conventional matrix acidizing procedure had been repeatedly applied in the field, but only half of treatments was successful. The effective period of acidizing treatments was short, injectivity of most wells decreasing within three to six months. To develop the optimal procedure for the field, we carried out studies on the acid-rock reaction mechanisms and the secondary damage mechanism during acidizing. We analyzed the spent acid ion concentrations from long-core lab tests, studied the pore structure using, Environmental Scanning Electron Microscopy (ESEM), and the rock compressive strength before and after the acidizing. A new procedure was developed based on the results of lab study. It features injection of organic solvent to remove the organic blockage caused by colloidal asphalt, followed by injection of low concentration organic acid. The wells were put on injection instantly after acid injection to push the spent acid further into the formation without flowback.
46 treatments that have been applied to the injectors in the Western and Eastern oilfield. Matrix acidizing of water injectors in low-permeability sandstone fields succeeded beyond all expectations. The injectivity increased 4 to 15 times, and the effective period has been increased from 6 to 18 months.
Damage Characterization of Deep Bed Filtration from Pressure Measurements
Authors: Bedrikovetsky P. , Tran P. , Van den Broek W. M. G. T , Marchesin D. , Rezende E. , Siqueira A. , Serra A. L. , Shecaira F. 
Published: December 2007

Abstract
Permeability decline occurs during injection of sea or produced water, resulting in well impairment. Solid and liquid particles dispersed in the injected water are trapped by the porous medium and may increase significantly hydraulic resistance to the flow.
We discuss a mathematical model for deep bed filtration containing two empirical parameters – filtration coefficient and formation damage coefficient. These parameters should be determined from laboratory coreflood tests by forcing water with particles to flow through core samples. A routine laboratory method determines the filtration coefficient from expensive and difficult particle concentration measurements of the core effluent; then the formation damage coefficient is determined from inexpensive and simple pressure drop measurements.
An alternative method would be to use solely pressure difference between the core ends. However, we have proved in earlier work that given pressure drop data in seawater coreflood laboratory experiments, solving for the filtration and formation damage coefficients, is an inverse problem that determines only a combination of these two parameters, rather than each of them.
A new method for the simultaneous determination of both coefficients is developed here. The new feature of the method is that it uses pressure data at an intermediate point of the core, supplementing pressure measurements at the core inlet and outlet. The proposed method furnishes unique values for the two empirical coefficients, and the solution is stable with respect to small perturbations of the pressure data.
In the current work the proposed method is used for analysis of laboratory test data on deep bed filtration. The values of filtration and formation damage coefficients are obtained for flow of solid and liquid particle dispersions in a number of different cores. Effects of particle type and porous media wettability on permeability decline are analyzed.
Measurements Of Fractional Wettability Of Oil Fields' Rocks By The Nuclear Magnetic Relaxation Method
Authors: Brown Robert J.S. , Fatt Irving 
Published: December 2007

Introduction
The wettability of reservoir rocks is recognized as one of the major factors that determines their multiphase flow properties. Multiphase flow properties in turn govern reservoir performance. For this reason, the reservoir engineer is vitally interested in the wettability of reservoir rock. The production research scientist is interested in wettability because the solution of the problem of improving water flood recovery by use of surface-active additives may hinge on a detailed understanding of the wettability of reservoir rock.
Early workers believed that all reservoir rocks were preferentially water wet. Continued study soon uncovered certain rocks which had flow properties that indicated that they were preferentially oil wet. Recent studies show that there is a spectrum of wettability. Some reservoir rocks have multiphase flow properties which indicate that they have an intermediate wettability. The differences in recovery observed among different reservoirs may, in part, be the result of small differences in wettability.
Differences in wettability among reservoir rocks may be the result of differences in the friction of the total surface area that is preferentially oil wet and preferentially water wet. Nuclear magnetic relaxation measurements provide a method for determining the fraction of preferentially oil wet and preferentially water wet area in porous media. Measurements to be reported here were made on water saturated unconsolidated sand packs which were mixtures of preferentially oil wet and preferentially water wet sands. The resulting data show definitely that the fraction of each wettability in the sand pack can be determined by this nondestructive method of measurement.
Underbalanced Drilling–Perceptions and Realities of Today's Technology in Offshore Applications
Authors: Hannegan D. , Divine R. 
Published: December 2007

Abstract
The Oil and Gas Industry drills thousands of wells globally each year, but what makes a well "successful" depends to a large extent on the perspective of the assessor. To the drilling engineer, a successful well is one that is safely drilled to target depth on time and under budget. The production engineer would add the need for there to be no, or minimum, formation damage and that the well achieve its maximum production potential. Unfortunately, these two aspects are rarely obtained within the same wellbore, due to the problems associated with the managing Equivalent Circulating Density (ECD) and the resulting fluid invasion, while drilling in the reservoir.
The management of ECD is "traditionally" achieved by drilling with mud, suitably weighted, to drill within a pressure margin until a casing point is mandated. This method has both benefits and detriments. The mud column provides primary well control in a conventionally drilled well, while the BOP equipment is secondary well control. This is the standard approach in the drilling industry, as mandated by regulatory agencies. However, it prevents approximately 20-30% of the known world's offshore oil and gas resources from being developed, due to excessive ECD when drilling. The tools and technology associated with underbalanced drilling (UBD) have added a beneficial dimension to ECD management. UBD tools and techniques are key to several emerging offshore technologies such as: drilling with subsea and surface BOP stacks with pressurized mud return systems, the concept of Dual Gradient Drilling, and using subsea rotating diverter control heads to control shallow water flows when drilling riserless. Underbalance drilling moves the primary well control from the mud column's hydrostatic pressure to the surface equipment where it is more easily managed and predictable.
This paper reviews key situations that are typically encountered when drilling offshore and make comparisons between "conventional" methods and UBD technology. The latest technology is reviewed to illustrate how drilling UB offshore can be safe and efficient to achieve a "successful" well from multiple perspectives. Such capability is now viewed by most majors as a requirement in many offshore situations to deal with depleted zones/reservoirs relative to water depth, narrow margins between fracture gradient and pore pressure, and for dealing with abnormally pressured aquifers (shallow water flow hazards). To date, the UBD applications used offshore have achieved an ECD nearer to reservoir pressure, thus minimizing skin damage from drilling fluid invasion.
Diagnostic Fracture Injection Test in Coals to Determine Pore Pressure and Permeability
Authors: Ramurthy Muthukumarappan , Marjerisson Douglas M. , Daves Scott B. 
Published: December 2007

Abstract
Permeability and pore pressure are critical parameters in the evaluation of a coalbed methane (CBM) project. Coal permeability is particularly problematic, as it is highly stress dependent and estimates made from cores generally do not adequately reflect in situ reservoir conditions. Pressure buildup, injection falloff and more often slug tests have been used to determine in situ permeability in coal. However, buildup tests are costly, time consuming, and cannot be applied effectively in underpressured reservoirs; slug tests require an accurate estimate of wellbore storage effects. Similar to buildup tests, injection falloff tests are very time consuming and costly because of the longer shut-in times. Also, if fracture pressure is exceeded during an injection-falloff test, conventional analysis can give erroneous results. This paper presents a more effective method for determining pore pressure and permeability in coals using a diagnostic fracture injection testing technique.
A diagnostic fracture injection test (DFIT) is a small-volume, cost-effective, and short-duration test that has been used successfully in tight gas sands in the Piceance and other basins. The test consists of (1) a G-function derivative analysis to identify the leakoff mechanism and closure, (2) a calibrated before-closure analysis using modified Mayerhofer method to determine the permeability, and (3) an after-closure analysis to estimate pore pressure and permeability. The uniqueness in applying this test in coals is that both the before- and after-closure analysis can be utilized where pseudo-radial flow is not dependent upon the fracture half-length. The technique works because the permeability in coals is high enough that after-closure pseudo-linear and pseudo-radial flows are normally observed with an extended shut-in. Once pseudo-radial flow is observed, estimating pore pressure and transmissibility becomes straightforward and provides calibration for the before-closure analysis.
Hundreds of diagnostic fracture injection tests have been conducted in all the CBM basins in the rockies and in Canada with remarkably consistent results. Examples are provided from San Juan basin and Canadian coals where diagnostic injection tests have been applied successfully for various operators. DFIT's have been applied successfully in other CBM basins like Sand Wash, Greater Green River, Piceance, and (western) Powder River basin.
Recovery Methods for Heavy Oil in Ultra-Shallow Reservoirs
Authors: Dunn-Norman S. , Gupta A. , Summers D. A. , Koederitz L. F. , Numbere D. T. 
Published: December 2007

Abstract
This paper discusses processes for sustainable recovery of heavy oil from ultra-shallow reservoirs, using low cost, innovative horizontal drilling and completion methods, combined with regional reservoir mapping and reservoir characterization.
Heavy oil exists in the shallow Pennsylvanian sands in Southwestern Missouri and Southeastern Kansas. These sands occur over an area of about 8,000 sq. miles that extends for 250 miles along the Kansas-Missouri border. Reserves are significant, with approximately 2 billion barrels of oil in Missouri alone1.
Recovery of the heavy oil in these shallow reservoirs has proven difficult. While the oil does flow into an open wellbore under natural conditions, flow rates are low due to the nature of the oil (18° API, 1000 cp.) and the low reservoir pressure due to shallow reservoir depth (&lt; 200 ft or 61 m).
Historically, industry has examined or attempted a number of development schemes including steam injection, CO2 flooding, in-situ combustion, direct electrical heating, stimulation with borehole explosives, and the application of solvents in conjunction with subsurface explosives. The most recent, and perhaps most successful development scheme included cyclic steam injection enhanced with flue gas. This project operated successfully for a number of years and resulted in average flow rates of 12 bopd.
Economic recovery of the ultra-shallow heavy reserves requires a process that is both inexpensive and easily applied. Novel, water-jet horizontal drilling and horizontal fracturing coupled with microbial enhanced oil recovery provide such a low cost method of recovery. This paper details these completion processes, their sustainability, and their potential for regional application. The paper also discusses the application of geochemical and/or shallow geophysical methods for regional mapping of the heavy oil sands, and the reservoir characterization methods for the shallow reservoirs.
Effective Stimulation Proved to be the Key to Economic Horizontal Completions in Low Permeability Carbonate Reservoir
Authors: Willett Ronald M. , Borgen Ken L. , McDaniel B. W. 
Published: December 2007

Abstract
When an operator is planning to drill a horizontal completion in a lower-permeability carbonate or sandstone reservoir, one of the prime well-design considerations is cost containment. Unfortunately, many operators use decision-making processes that are inappropriately weighted toward cost reduction and insufficiently or incompletely weighted toward incorporating completion processes that will ensure adequate producing rates. As a result, the ultimate hydrocarbon recoveries that were used in the economic justification of the program may not be achieved.
This paper presents a case study of a multi-year horizontal completion project in west Texas that was very successful in exposing the "false economy" of not cementing casing in horizontal wells drilled in low-permeability reservoirs. Increasing initial well costs about 20 to 25% resulted in a 3-to 10-fold increase in economic returns. This project included wells drilled in the heart of the play, in one of the flank areas, and also in an "edge" portion of the field, with comparisons to openhole completions in each area. The project offers several guidelines that should be followed by almost any global application of horizontal completions in lower-permeability reservoirs.
Northstar Drilling-Delivering the First Arctic Offshore Development
Authors: Krieger Andrew G. , Kidd Gavin N. , Cocking David A. 
Published: December 2007

Abstract
Drilling oil wells on the North Slope of Alaska is not a new endeavor. Thousands of wells have been drilled over the past two decades in order to fill the Trans Alaska Pipeline. The majority of these wells have been drilled from a number of large drilling pads connected via a road network. Some of the newer developments have been drilled from remote pads accessible by fixed wing aircraft and ice road during the winter. So what is it that makes the Northstar Development stand out among all other drilling operations on the North Slope? It is the first Arctic Offshore Development that is not accessible by road for most of the year and does not have fixed wing air support. The implications of limited access to a 400’ by 400’ island are enormous. Successful completion of the first drilling season at Northstar is a significant milestone marked by detailed design and execution as well as pure determination. Many of the challenges were anticipated and accounted for while many others were not. The first Arctic Offshore Development delivered its first barrels of oil as per schedule on 2nd November 2001. Now comes the next challenge-drilling more for less to improve the profitability of this unique Alaskan project.
Evaluation of Hydraulic Fracturing and Re-Entries in the Hassi-Messaoud Field, Algeria
Authors: Rahmouni Noureddine , Tiab Djebbar , Azzoughen Athmane , Mazouzi Amine , Escobar Freddy H. , Zhu Tao 
Published: December 2007

Abstract
Since 1990, two emerging techniques, hydraulic fracturing and re-entry techniques, have been applied in HMD Field, Algeria, to increase oil production. This paper analizes the production data for more than 17 re-entries and 60 fractured wells. The results indicate that oil production from 13 out of 17 re-entries declined rapidly to below the original level within a year, and 31 out of 60 fractured wells are not profitable. To analyze the well performance from field data, a 3D simulator was used to evaluate both hydraulic fracturing wells and re-entries. Several scenarios were built for each technique. The effect of fracture length, fracture width, fracture height, re-entry length, pay zone, and oil price on technical and economical success was analyzed. Risk analysis was used to take into account of practical, economical, and other unexpected factors. The results show that fractured wells are profitable but not for re-entry wells.
New Methods for Sand Cleanout in Deviated Wellbores Using Small Diameter Coiled Tubing
Authors: Engel S. P. , Rae Phil 
Published: December 2007

Abstract
The use of coiled tubing to remove sand from well bores was one of its earliest applications and continues to be an important service today. In fact, sand clean out operations in the Asia Pacific Region still represent some 30% of CT service activity. However, the trend towards more complex well trajectories and reduced topside facilities offshore can impose operational constraints on this essential service.
This paper describes a method of transporting sand out of low-pressure wells, of any angle, using small diameter coiled tubing. It describes the philosophy employed as well as the technical and economic rationale behind that approach. A case study reviews some unique rheological properties of sand suspension fluids and field performance characteristics.
The industry has developed a number of alternative solutions to sand removal, including concentric pipe, wiper trips, jetting techniques and the deployment of large diameter pipe. With the commercial constraints of the service business, depleting reservoir pressures and increasing numbers of high angle wells, the method described supplements the current range of clean out solutions with its elegance, simplicity and logistical merits. This technique involves particle entertainment at the BHA to fluidize the sand and subsequent displacement from the well at low velocities. The main benefit of the system is the avoidance of the need for large diameter, heavy and expensive hardware and the ability to operate in areas where weight restrictions exclude the use of larger equipment.
Assessment of Risk and Size Dependencies in a Geologic Play with Multiple Zones and Multiple Prospects
Authors: Wang B. , Kokolis G. P. 
Published: December 2007

Abstract
This paper describes a precise method to assess twodimensional, partially dependent risks for geologic plays that contain both multiple zones and multiple prospects. Prior methods have considered only one-dimensional solutions; that is to say, plays with risk dependencies between either multiple zones or multiple prospects, but not both.
Decision-tree methods are used with the input of assumed vertical and horizontal dependencies for multiple geologic controls (such as charge, reservoir, structure, and seal), along with the assumed initial geologic control risks, and the assumed chance of drilling for each prospect. Throughout the calculation process, the weighted-average dependent risks are maintained as identical to the initially assumed risks. This rule of "risk conservation" must be honored to avoid unintentionally over or under estimating the evolving risks which result as wells are drilled and prospects and zones succeed or fail.
This paper details the logic and calculation procedure that we use to estimate the overall chance of success and potential resource size for a play with two-dimensional risk dependency. A spreadsheet program can be used to implement the calculations. A complete risk evaluation of a 3-zone, 6-prospect lease block is demonstrated.
We also investigate the impact of resource size dependency in play assessment. In the past, size dependency was generally ignored to simplify calculations. Size dependency will not change the overall geologic risk or the mean geologic resource estimate of a play. It can; however, alter the overall resource distribution (e.g. variance and resulting P10, P50, P90) and the commercial (or truncated) risk and mean resource estimates. Consideration of size dependency is important for plays with highly dependent risk factors, but not important for plays with independent risks.
Multiwell Interference Test in the Colville River Field, Alaska
Authors: Erwin Mike D. , Sanders L. Allen , Redman R. Scott 
Published: December 2007

Abstract
This paper documents a unique pressure transient test conducted prior to start-up of the largest onshore oil field discovery in North America in the past decade. In March 2000, a multi-well interference test was initiated to enhance understanding of field scale reservoir continuity, permeability, fracturing and injectivity. Testing began eight months prior to ‘first oil’ involving eleven development wells. This inventory of completed idle development wells prior to field start-up provided a unique opportunity to pulse test a ‘silent’ reservoir.
Determining Reservoir Stratigraphic Continuity via Well Testing in Deepwater Gulf of Mexico, Fuji Prospect
Authors: Haddad S. , Cribbs M. 
Published: December 2007

Abstract
The Fuji Prospect is located in the Green Canyon Blocks 505 and 506 approximately 180 miles south-southwest of New Orleans in a water depth of 4,280 ft. The discovery well, Fuji Well #1 (Green Canyon 506 Well #1) encountered 182 ft of oil pay in four Lower Pliocene age sandstones and was temporarily abandoned in 1995. The second well, Fuji Well 2 (Green Canyon 505 Well #1) was drilled in 1997. The well encountered 214 ft of oil pay, in sands equivalent to the pay sands and some wet sands seen in the discovery well.
Well tests were performed on two pay sands. Both tests had low productivity rates of less than 5000 BOPD and recorded pressure depletion. The 1st test indicated a small compartment. The 2nd test was inconclusive and could be explained by either a small compartment with high permeability or a larger compartment with very low permeability.
The Fuji Well 3 (Green Canyon 506 Well No. 2) was drilled next, in a structural position between Fuji Wells 1 and 2 in order to confirm stratigraphic continuity of the reservoirs. It penetrated 227 ft total of oil pay sands and 123 ft of oil pay in the shallower interval. The main field pay sand was the Magenta Sand, which was tested in Fuji Well 3 at a rate of 7,192 BOPD. The Magenta Sand in Fuji Well #3, however, showed pressure depletion during the test. Fuji Well #3 was temporarily abandoned in March 1998.
The Fuji #2 and Fuji #3 well test design and results will be presented. Pressure transient interpretation challenges and conclusions will be discussed. This work will also demonstrate the impact of well testing on determining stratigraphic continuity and reserves calculations.
Identification of Steam Breakthrough Intervals Using DTS Technology
Authors: Johnson D. O. , Sugianto R. , Mock P. H. 
Published: December 2007

Abstract
With the development of several novel methods for installing optical fibers in oil and gas wells for the purpose of "Distributed Temperature Sensing" (DTS), the search is on for gaining the considerable value offered from this remarkable technology. An Extremely cost effective and accurate method of determining steam breakthrough in producing wells has been developed which takes advantage of the power of DTS technology.