bluuebunny/crossref_metadata_2025_split huggingface dataset:
Obtaining Permeability Values in a Coalbed Methane Core-Hole Utilizing Slimhole Technology Coupled With an Injection/Falloff Technique
Authors: Rodvelt G. , Toothman R. , Hayhurst J. , Oestreich R. 
Published: December 2007

Abstract
It has been a common practice in the industry to obtain core samples to determine gas content for coalbed methane (CBM) projects; however, due to economic issues, permeability testing has usually been avoided. To obtain core samples, the core hole is drilled, samples are collected, and the core hole is plugged per state regulations. Obtaining permeability test results in an openhole core hole on the other hand is time consuming and does not provide consistent results. However, if permeability testing initially could be completed in the core hole, not only could time and money be saved, but permeability data, core data, and logging information could all be tied together from the same wellbore. An informed decision could then be made based on this additional information to help determine whether to move forward with the project or move to another area.
The authors present a process that includes drilling a 3 1/2-in. core hole, collecting a 3-in. core, cementing 2 7/8-in. tubing, and conducting permeability testing using an injection/falloff technique. A unique cement blend is presented that reduces cement loss to the cleat system while providing a lightweight blend with "zero" free water and low friction pressures for placement. A test assembly consisting of slimhole packer, downhole shut-in device, and downhole pressure gauges is run in the hole on 1 1/2-in. tubing to provide isolation, eliminate wellbore storage, and record bottomhole pressure and temperature. A self-contained permeability test trailer capable of pumping and recording rates as low as 0.03 gal/min is essential to this process. The objective of the test is to inject fluid at matrix rates without fracturing the coal seam, then analyze the data using conventional well testing software and a CBM reservoir simulator to arrive at permeability and reservoir pressure. Production forecasting can then be simulated for project review.
Reservoir Knowledge and Drilling—Benefits Comparison for Underbalanced and Managed Pressure Drilling Operations
Authors: Finley Doug , Shayegi Sara , Ansah Joe , Gil Isabel 
Published: December 2007

Abstract
The industry is now becoming more knowledgeable concerning underbalanced drilling (UBD) and managed pressure drilling (MPD). These techniques are gaining popularity because of their capability to control severe fluid losses and other problems that are inherent to conventional overbalanced drilling. As a result, considerable increase in their usage has been noted; however, with these increases, it has become apparent that there is a great deal of confusion concerning the basic concepts of each technique and when each should be used. Generally speaking, UBD can be described as a reservoir performance improvement and characterization tool that also provides drilling benefits. Another advantage is that UBD can offer a unique well testing environment in which the properties of reservoir layers can be determined while drilling. MPD, on the other hand, primarily addresses drilling-related problems that result in nonproductive time (NPT) in drilling scenarios. Sometimes, however, there are well scenarios in which both techniques might be needed in different hole sections.
Reservoir information gained during underbalanced drilling also can help reduce the time and cost associated with gathering and analyzing well-test data post-completion with conventional methods. Techniques have been developed to quantify reservoir properties and characteristics for homogenous and heterogeneous and/or fractured reservoir systems.
This paper focuses on where each concept should be used and what benefits can be expected from their application. Results from UBD and MPD case histories are used to quantify the results from these operations. Differences between the two techniques concerning equipment requirements and reservoir characterization potential are also analyzed.
New Wells and New Challenges: Selecting the Most Appropriate Drilling and Drilling Fluid Practices
Authors: Pratap K. Krishna , ThyagaRaju B. A. , Kali A. T. 
Published: December 2007

Abstract
The development of giant oil field "Mumbai High" has been a learning platform for the role that drilling fluids play in the successful rejuvenation program of any oil field. This paper attempts to manifest the learning curve right from the low angle wells drilled using simple conventional systems limiting the role of fluid services to the basic functions of enabling the normal drilling process. Over the years when farther parts of reservoir were explored at higher angles, the crucial role of the inhibition, bore hole stress management were exposed. The ultimate challenge was posed by the horizontal program where in the grey areas of cutting bed formation, hole cleaning, imperative drilling and drilling fluid practices dictated the completion of any well. The final Phase of the ERD program showed the critical aspect of minimization of pore pressure transmission and gauge of hole to the successful drilling of any well. The chronology has dictated the imperative selection of the right drilling fluid for each phase starting from the change over to the non-dispersed KCL-PHPA systems the Cloud point Glycol system via the most inhibitive Silicate system and culminating with the selection of Synthetic Oil Base Mud for the long horizontal wells. The redevelopment program indicated that there are no degrees of freedom as far as the inhibition, hole cleaning, bore hole stress management and drilling practices are concerned, and that is up to the drilling fluid chemist to play a proactive role to fill in the grey areas between the driller, G&G and the drilling fluids.
Overcoming the Challenges of Building 3D Stochastic Reservoir Models Using Conceptual Geological Models—A Case Study
Authors: Al-Khalifa Mohammad A. , Payenberg Tobias H. D. , Lang Simon C. 
Published: December 2007

Abstract
Construction of reliable 3-D geological models for reservoir simulation requires a detailed understanding of facies distribution and connectivity within the interval of interest. In particular, it relies on lateral and vertical variabilities in reservoir quality within and between different flow units. Despite thorough data integration and interpretation, several challenges were encountered while integrating geological knowledge into a 3-D stochastic geological model.
Some unconventional approaches had to be taken in order to best reflect the geological understanding of the reservoirs while using commercially available software. For example, the 3-D stochastic facies modelling of the reservoir units was based on conceptual geological models. Models were constructed for each reservoir zone through the analysis and integration of core and log data from 50 wells in the study area. However, it was seen that utilising either object modelling or pixel-based modelling methods alone would not generate stochastic models that adequately honoured the conceptual geological model. Consequently, the two modelling methods were used together to generate combined models.
A further challenge was to determine adequate facies proportions for each reservoir zone. The direct use of facies statistics from well logs in stochastic modeling lead to unrealistic facies distributions. To overcome this, dummy wells were added to make facies proportions matches the conceptual models rather than basing it on the existing wireline logs alone.
Taking these unconventional approaches lead to a greater accuracy of reservoir and porosity distribution around the reservoir. Moreover, the methodology used in this study provides new ideas that can be used in modeling other fields with fluvial depositional settings.
Revitalizing the Richard King Field: Using New Technology in a Cost-Effective Manner on Mature Fields
Authors: Swanson Jeff , Stevens Greg , Hall Rod 
Published: December 2007

Abstract
What else can be done to an old field where past operators have tried just about everything including 3-D seismic? If there is anything else, would it add quantifiable value to the property?
As an acquirer of mature properties, this common challenge for Durango Resources Corp. ("Durango") was dealt with by combining old-fashioned geological and engineering methods with new technology. Some of these methods included thorough data gathering and detailed analysis of the stratigraphy and depositional environment of all well logs.
Completing a detailed field study combined with new technology has resulted in new life for the old field and has added definable value to the property.
Granite Wash Field Study—Buffalo Wallow Field, Texas Panhandle
Authors: Ingram Stephen , Paterniti Isaac , Rothkopf Brian , Stevenson Chris 
Published: December 2007

Abstract
One of the major producing zones in the Texas panhandle is the Granite Wash. The Granite Wash play is currently focused on Wheeler and Hemphill counties on the Oklahoma border and covers more than 1,000 sq mi of tight-sand formations. The focus is less on discovery and more on cost reduction in drilling and stimulating wells. The Texas Railroad Commission in some cases has lowered spacing to 40 or 20 acres per well, which, along with steadily high gas prices, form the basis of the high rig count working in the region.
Because of the lack of concise and consistent nomenclature in the Granite Wash plays of the Anadarko Basin, this case study addresses the stimulation trends the industry is using in the Wash play. The target area of this study consists of three counties located in the Texas Panhandle: Wheeler, Hemphill, and Roberts, with extensive data only within the Buffalo Wallow Field. This paper discusses the reservoir development and characteristics, current and former completion techniques, and production comparisons. The goal for this study is to determine best practices for completion procedures in the Granite Wash.
Previous satabases1 have been expanded using detail data on fracture treatments performed and production recorded from 135 wells over the given period from 2002 through early 2006. The operator and service provider are currently analyzing the data. The goals of this analysis are to (1) define basic criteria (rules of thumb)2 for optimizing the potential for the highest initial production and 90-day cumulative production, and (2) discover correlations, if any exist. The data of interest reside in each well's specific fracture treatment data that includes the following, but is not limited to treatment rate, proppant volume, treating fluid volume, gross pay interval, net pay interval, proppant mesh size, and treating pressure.
One example of the correlations obtained is: based only on rate, if the treatment is pumped at a minimum of 100 bbl/min, a good well will be achieved 66.7% of the time versus 55.2% when the treatment is pumped below 100 bbl/min. When the production criterion is 60-day cumulative production, the gap lessens: 65.6% when the treatment rate is over 100 bbl/min; 60.7% when the treatment rate is less then 100 bbl/min. Many other correlations regarding perforated interval, treatment volume, proppant mass, proppant sieve size, etc. are presented in this paper.
New Methods and Equipment for Dewatering Unconventional Gas Resources Using Sucker-Rod Pumping Equipment
Authors: Mahoney Mark W. , DeWerff Randy 
Published: December 2007

Abstract
Dewatering coalbed methane and low-pressure gas wells has been a challenge for oil and gas producers. When compared to ESP and PC pumping, sucker rod pumping is a very forgiving method and wells can be pumped to very low pump intake pressure without damaging the pumping equipment. This has generated a strong interest in using sucker rod pumping in dewatering gas wells. Quite often operators try to use sucker rod pumps and rod pump system designs that are the same types used for pumping single phase (liquid) fluids and they do not achieve the desired fluid removal and are not designed to handle sand, coal fines and other solids encountered in this type of production. New designs in sucker rod-pumping equipment and rod-pumping systems for high GLR, coal fines and solids have greatly changed the approach to dewatering unconventional gas resources. This paper will examine the new equipment and design criteria being used to help dewater gas wells.
Successful Application of Relative-Permeability Modifiers To Control Water Production in Rose Run Fracturing
Authors: Fry Len , Everett Don , Moody Mark , Hina Brad , Gessel Jim , Gessel Steve 
Published: December 2007

Abstract
A number of wells in the Rose Run formation of Ohio were all completed with small acid treatments and placed online within the last 12 years. These wells are approximately 20 miles west of Canton, near Brewster.
Reductions in well performance over short periods of time indicated the need to stimulate the wells. Fracture stimulation has not been widely used in the area due to the potential water production resulting from fracturing out of zone. The objective of the hydraulic fracturing treatments in these wells was to obtain a short, highly conductive propped fracture past the damaged area. Fracturing models were used to determine the fracture geometry.
In an attempt to minimize post-fracturing water production, a relative permeability modifier (RPM) was pumped as a preflush to the fracturing treatment. Fracture designs were based on individual well characteristics. The RPM was designed to effectively reduce the relative permeability to water without significant changes to the hydrocarbon relative permeability. A low gel-loading borate crosslinked fluid was then used to fracture-treat the wells.
A total of 12 wells were fractured with the RPM ahead of the fracturing treatment. The results of these treatments were compared to offset wells that were fracture-treated without the RPM. The increase in water production in the RPM-treated wells was one-half that of the offset wells. These RPM-treated wells also had lower water-oil ratios (WOR) and water-gas ratios (WGR).
This paper will describe the properties of the RPM, the Rose Run formation, as well as, the treatment designs. It will also detail the post-fracturing results and the comparisons with the offset wells.
Slickwater Technology Helping Greene County Enhance Natural Gas Production
Authors: Mills Robert D. 
Published: December 2007

Abstract
The Appalachian Basin is known for producing wells that have extreme longevity to include wells that are still producing after 30 or more years. The last several years, Greene County in Pennsylvania has become an active area. The producers have been drilling the Upper Devonian sandstone at depths of 2500 to 5000 feet. Various formations including the Bradford, Speechley, Balltown, and Fifth Sand are typical in a completion of the wells. The conventional completion method has been to utilize a cross-linked polymer gel system. A newer approach utilizing slickwater technology being used on some shale formations has been modified for use in Greene County.
The formations commonly average between 4 to 20 feet of net productive reservoir per zone with 6 to 9 percent porosity, and 50 to 80 percent gas saturation. The formations have been difficult to initiate a fracture. Once a fracture has been initiated, transport of proppant into the zones has also been difficult. Screen-outs have been common in stimulating the tight zones.
During the flow-back process of a screened-out zone, probable formation particles were observed accompanying the sand during the latter stages of the flow-back. Analysis of the log and flow-back particles indicated the particles were primarily a siltstone or shaley-sandstone. Potential pay zones that show a siltstone or shaley-sandstone composition were selected and treated with a slickwater pre-pad.
The volume of slickwater has been 20 to 30 percent of the total volume of the treatment. The slickwater treatment is being used to connect the minor fingerlike fractures within the zone that show shale characteristics. It is believed that the slickwater treatment extends the total fracture length while stimulating the formation. The minor fractures are believed to contribute substantially to the production within the tight gas sands of the Devonian sandstone.
A cross-linked polymer gel used to transport proppant follows the slickwater treatment. The fluid used for proppant transport is guar based. The fluid is chemically enhanced while being pumped down the casing to give higher viscosity and proppant transportability. Proppant loading ranges from 0.5 to 3 pounds proppant added.
Early production data is showing an increase in initial well production. The production increases have been sufficient to continue the treatments. The increased initial production helps decrease the time required to see a return on the investment for the producer.
Performance Evaluation of a Reservoir Under EOR Recovery: Intisar ‘D’ Reef, Concession 103, Libya.
Authors: Vilela M. J. , Gharsalla Mohammed , Elghmari Mohamed , Majdoub Abdulhamid 
Published: December 2007

Abstract
The Intisar "D" reservoir is a carbonate reef of Paleocene origin with no appreciable flow barrier. This is an under saturated reservoir with an oil of 40 °API and solution gas oil ratio of 595 SCF/STB. The reservoir, having 452 ft of net pay, is at a datum of 9,000 ftSS with an initial OOIP of 1.76 billion stock tank barrels and initial reservoir pressure of 4,257 psia. A series of very successful reservoir management strategies have been applied in order to optimize and increase the production capacity and reserves. So far 69.2 % (1.2 MMSTB) of OOIP has been recovered mainly due to implementation of an EOR project.
From the commencement of production in 1969 up to 1981, Intisar "D" was under bottom water injection for reservoir pressure maintenance and crestal hydrocarbon gas injection for pressure maintenance, gas conservation and enhanced oil recovery; then water injection was halted, but gas injection has been continued successfully until now. Against common knowledge, oil recovery to gas (immiscible) was more effective than water flooding.
For analysis purposes the reservoir was divided in two portions: Water Swept Zone (WSZ, from the base of the reservoir up to the level of WOC in 1981) and Gas Swept Zone (GSZ, from the level of WOC in 1981 to the top of the reservoir) to separately evaluate the displacement sweep efficiencies. Gas injection at the crest of the reservoir has been an extremely successful drive mechanism, although this process has been immiscible most of the time. To December 2005 cumulative oil production was 1,218 MMSTB, of which 823 MMSTB were driven due to gas injection as secondary and tertiary recovery methods while 395 MMSTB were produced due to waterflooding.
This is one of the biggest EOR processes worldwide.
This paper discusses the strategy used to produce this reservoir and also to compute the produced oil recovery from the different drive mechanism employed.
Trapped Annular Pressure—A Spacer Fluid That Shrinks
Authors: Bloys B. , Gonzalez M. , Hermes R. , Bland R. , Foley R. , Tijerina R. , Davis J. , Cassel T. , Daniel J. , Robinson I. , Billings F. , Eley R. 
Published: December 2007

Abstract
In deepwater or other sub-sea completed wells, fluids, usually spacers or drilling fluid, are commonly trapped in casing annuli above the top-of-cement and below the wellhead. When these trapped fluids are heated by the passage of warm produced oil and gas, thermal expansion can create very high pressures (10,000-12,000 psi or more) and cause the collapse of casing and tubing strings.1,3,11,14
Mitigation methods such as vacuum insulated tubing to limit heat transfer,5,6,13 nitrogen foam spacers to give highly compressible trapped fluids,7,8,9,10 crushable urethane foam insulation,2 etc. are somewhat successful but are either very expensive, logistically troublesome or have unacceptable failure rates. This paper covers a new approach which has created a water-based spacer fluid that will be used just ahead of the cement. The spacer contains perhaps 20-40% of emulsified methyl methacrylate monomer (MMA). Upon polymerization, the MMA phase shrinks by 20%, creating room for the remaining fluid to thermally expand without creating catastrophic pressure. The polymerization is triggered by heat and the target temperature can be controlled by an appropriate type and concentration of chemical initiator. Premature polymerization during spacer placement can be prevented by an appropriate type, and amount, of inhibitor.
A spacer formulation (viscosifier, emulsifiers, MMA, weighting agent, inhibitor, etc.) has been developed which covers the range of densities expected in deepwater wells. A matrix of bench top tests has determined the types and amounts of initiator and inhibitor needed to adjust the temperature of the polymerization to the range of temperatures expected in the field. These results have been confirmed in an advanced pressure-volume-temperature (PVT) cell that closely simulates downhole conditions. A successful mid-scale field trial has been conducted in a 500-ft test well using normal oilfield casing, drillpipe, pumps, etc. A method was devised to add the initiator on-the-fly as the spacer is pumped downhole. Safe handling procedures have been developed for mud plant mixing, transportation, and rigsite application. The new spacer will be tested in an onshore well in the near future, and then in several deepwater wells prior to commercialization.
Porosity Partitioning and Flow Unit Characterization from an Integration of Magnetic-Resonance and Borehole-Image Measurements
Authors: Pal Aditi , Seth Kapil , Guru Udit , Tiwari R. R. , Dasgupta D. 
Published: December 2007

Abstract
The petrophysical evaluation of carbonate reservoirs in terms of predicting the hydrocarbon potential is trivial. However, it is difficult to correctly predict the fluid flow in the absence of proper characterization of the different flow units encountered in these reservoirs. The process of identifying the flow units becomes non-trivial in the presence of extensive diagenesis process affecting the original depositional texture. The conventional triple combo logs gives an average response when logged against diagenetically altered zone thus overlooking or under-estimating diagenetic features occurring in micro scale. It becomes imperative to look at both micro and macro scale heterogeneity for evaluation of such reservoirs, which has a direct impact on the production, and water injection scheme of such reservoirs.
The NMR data and image based secondary porosity estimation recorded in this well were used for partitioning the porosity into micro, meso and macro porosity. Borehole image logs have been interpreted in terms of defining the connectivity of the features seen on the image. This is then used to define a high-resolution connectivity index. An integrated approach using the NMR and the image is being proposed to identify such high permeability streaks that can explain the production performance or the water injection behavior at a later stage of development of the field. Based on the porosity partitioning technique an improved permeability estimate is made. The production results confirm the findings of this study.