Gamma Ray Tracers Help Evaluate Acid Diversion

The use of multiple gamma ray tracers has helped evaluate acid diversion in several North Sea completions. The use of multiple radioactive tracers and subsequent logging with advanced gamma spectroscopy techniques offers a cost-effective and convenient method for direct measurement of vital stimulation parameters such as diverter effectiveness.

Productive intervals in the Norwegian sector of the North Sea tend to be quite thick: Danian pay ranges up to 550 ft, and Maestrichtian up to 500 ft. Average porosity can reach 48%, and matrix permeability varies from less than 0.1 to 5 md. Well productivity seems dependent on the degree of natural fracturing, and pressure transient testing derived permeability estimates can be as much as 75 times the matrix permeabilities obtained from core measurements.

Perforations are placed in 10-to 20-ft clusters spaced 40 to 80 ft apart, with a shot density of 2 shots/ft throughout each cluster. The acid stimulation treatments are then pumped in multiple stages, with each stage consisting of a viscous pad, acid, overflush, and diverter (ball sealers are most often employed).

The tracer studies outlined in this article were conducted on six stimulation treatments to determine if the diverter techniques employed result in relatively even treatment of all pay, and to evidence the creation of multiple hydraulic fractures. All evidence suggests adequate diversion usually occurs and new fractures are propagated on each stage.

The specific tracer technique used involved the placement of a different discernible gamma emitting tracer in each stimulation stage to determine its relative placement and thus infer the effectiveness of the diverter stages. Three tracers, Antimony (124Sb), Iridium (192Ir), and Scandium (46Sc) were added to each stage to differentiate the placement of up to three stages or groups of stages. Following each treatment, a Prism® log was run to identify tracer placement. A detailed description of the materials used and the tagging and logging techniques were discussed in earlier articles.

The tracers were prepared as ceramic particle encapsulations, with a mean particle size of 0.5 mm. This proprietary preparation exhibits a tracer washoff of less than 0.01% in 28% HC1 at 100xC, and has a specific activity of approximately 0.89 mCi/gm (32.8 MBq/gm) or 0.0014 mCi/particle (0.0527 MBq/particle). The use of these tracers in particulate form was preferred to using soluble forms to minimize environmental concerns of returning radioactive residue to the surface with the flowback of the spent acid. The tracers and the equipment used to inject them into the stimulation process were transported to the well platforms from the UK aboard the service company's vessel performing the treatment. Generally, about 20 mCi (740 MBQ) of each tracer was injected continuously throughout each acid stage. Specific licensing to perform the radioactive tracer studies was required from Norway's National Institute of Radiation Hygiene.

The wells were logged using a 1.6875-in. (4.2863-cm) OD Prism tool, which contains a 1-in. by 6-in. scintillation crystal. The logging speed was 500 ft/hour (152.4 m/hour). At each 3-in. (7.62 cm) interval, the entire 256-channel gamma ray spectrum was encoded and transmitted to the surface and recorded on magnetic tape. This data was subsequently processed using the proprietary software on a microcomputer at a log analysis center in Stavanger, Norway. The software mathematically unfolds the gamma ray spectrum to determine tracer yields and indicate the location of individual isotopes along the well bore. Furthermore, the program determines the lateral tracer placement (inside or outside the casing) by using a photopeak to downscatter ratio.

The results of the six tracer studies are presented in tabular form in Table 1. The Prism logs from wells A, B, and C are presented as Figs. 1,2, and 3, respectively.

In summary the following conclusions are made:

• Tracer materials of the type and packaging used are effectively placed in the formation and do not flow back into the well. In consequence, reliable Prism data may be obtained in one pass after cleanup flow of the well.
  
• Where the cement bond log indicates effective mechanical isolation of perforated zones in the treated interval and the number of perforations is low, good diversion occurs.
  
• Breakdown of both single and multiple zones on individual stages were observed.
  
• Limited fracture heights and formation of multiple fractures occurs.
  
• Tracer material positioned during the early treatment stages is partially stripped away during the later stages. This is particularly apparent when the number of perforations is low and flow velocities will, in consequence, be high.
  
• The logging technique and analysis allows us to determine the placement of isotopes in the presence of radioactive scale.

Tracers Can Improve Hydraulic Fracturing, J.W. Chisholm, Petroleum Engineer International, July 1989.

ABSTRACT

Tracers Can Improve Hydraulic Fracturing

Because the success of well stimulation treatments often dictates the economic justification of petroleum field development, much effort has been devoted to the measurement of various parameters associated with this critical and costly operation. specifically, the prediction, measurement, and optimization of induced hydraulic fracture geometry is an endeavor which has resulted in a major industry-wide research effort. in the past 10 years, extraordinary advances have been made and the evolution of well stimulation technology is still proceeding at an incredible rate.

Many methods of actually measuring or inferring fracture geometry during or after a frac treatment have been developed and tested; however, few are considered sufficiently pratical, convenient, and cost-effective to be performed routinely. Analysis of pressure data from frac treatments and prefrac injection tests can lead to quantification of certain fracture parameters such as closure stress, fluid efficiency, and leakoff coefficient; however, computation of most of these properties requires knowledge of the vertical fracture height.

Of all the available vertical fracture height measurement techniques, post-treatment tracer and temperature surveys are by far the most common because they are convenient and relatively inexpensive to conduct. Temperature surveys can provide quantitative vertical fracture height determinations; however, they are plagued by the following problems:

• Cross flow and pressure-induced fluid redistribution following the treatment can result in temperature surveys that are difficult to interpret.
• In wells where the formation temperature differs only slightly from the surface ambient temperature, these surveys are not possible.
• If significant amounts of proppant remain in the well bore and must be circulated out before logging, the circulation process may distort the temperature anomalies created by the frac treatment, or the temperature anomalies created by the treatment may completely dissipate by the time the temperature survey can be conducted.

Because of these problems particularly the last, frac treatments are frequently tagged with radioactive tracers. The major objections to using gamma emitting tracers have been that:

• Only single tracer operations were pratical, unless tedious multiple logging runs using tracers with greatly differing half-lives were conducted.
• A conventional gamma ray log cannot differentiate tracer material actually placed in the formation from residual tracer left in the well bore; thus, the determination of actual vertical fracture height is often obscured.
• The depth of detection from the well bore is limited to less than a meter unless excessive concentrations of radioactive tracer are employed.

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Tracer Technology Finds Expanding Applications, T.R. Bandy, Petroleum Engineer International, June 1989.


ABSTRACT

Tracer Technology Finds Expanding Applications

Tracers are becoming a commonly used tool to study the production, injection, and processing of oil field fluids. Additionally, tracers evaluate the placement mechanics of well completion fluids and slurries. Other related fields, such as geothermal energy, hydrology, and underground storage-disposal, have also applied tracers to aid in the understanding and subsequent optimization of their specific operations. Not unexpectedly, the phenomenal advances in electronic instrumentation and computer science have brought about an evolution in the detection of tracers and analysis of tracer tests.


The Random House Dictionary defines a tracer as "a substance, usually radioactive, traced through a biological, chemical, or physical system to study they system". Indeed, tracers of every conceivable form have been formulated to satisfy the requirements of this definition. Thus tracers of all three physical states (solid, liquid, gaseous) and a myriad of chemical compositions of each are available. Most oil field tracer applications require downhole detection via wireline conveyed instruments; thus, the use of gamma-ray emitting radioactive isotopes is quite common. In other applications such as interwell tracer testing, the collection of produced fluid samples and subsequent direct analysis require the use of many different types of tracers. Generally, tracers can be categorized as follows:


• Gamma-ray emitting radioactive tracers (can be detected downhole).
• Particle emitting radioactive tracers (cannot be detected downhole).
• Chemical tracers (both organic and inorganic).
• Optical tracers (dyes and flourescents).

When selecting various tracers for specific applications, certain criteria must be considered; the most important factor is the accuracy with which the tracer will follow the material being traced. Partitioning of the tracer into a phase other than the one of interest has resulted in many invalid tracer tests. Also, the amount of tracer used must be sufficient to account for the following:


• Naturally occuring concentrations of the tracer species.
• Adsorption onto tubulars or formation during transport.
• Molecular diffusion, fluid dispersion, and dilution.
• Chemical and biological degradation.
• Radioactive decay (half-life).
• Interference of other matter with detection technique.

Additionally, in downhole detection of gamma-ray emitting tracers, the distance between the tracer and detector and the shielding values of the materials separating them must be considered. Radiation intensity follows the inverse square law with respect to distance; thus, if the distance between a gamma-ray emitting tracer and the detector is increased from 2 to 4 ft, the gamma-ray intensity will be only one-fourth the original value. Furthermore, dense materials (such as steel pipe) can greatly diminish radioactive tracer detectability.


Because of these two factors, downhole detection of gamma-ray emitting tracers has undergone considerable improvement, beginning with techniques for discerning relative placement of tracers inside the well bore versus in the formation2 and differentiation techniques for multiple tracers. Two works published within the last year describe an analytical spectrum unfolding technique, and a relative distance measurement technique which ultimately should lead to true radial quantification of such near-well bore treatments as primary cementing and gravel packing.


In downhole well logging, the industry has used gamma-ray detectors for many years to measure naturally occurring radiation followed by processing of the spectral data into potassium, uranium, and thorium equivalents. These natural gamma-ray spectroscopy instruments, historically housed in large diameter tools (3-5/8-in. OD) have recently been augmented with smaller diameter (1-11/16-in OD) tools so that through-tubing operations now can be conducted.


Additionally, calibration of these spectroscopy tools for use in differentiating multiple gamma-ray emitting tracers, and their placement relative to the well bore (inside versus outside) have been conducted in the laboratory. All these recent efforts have resulted in numerous field-proven services, readily available throughout the industry.


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Using Tracers to Evaluate Propped Fracture Width, S.A. Holditch, David Holcomb, Zillur Rahim, SPE 26922, November 1993.


ABSTRACT

Using Tracers to Evaluate Propped Fracture Width

Many production engineers are beginning to use three-dimensional (3-D) fracture propagation models to design and analyze hydraulic fracture treatments. To use a 3-D model, one must define the layers that comprise the reservoir and develop detailed datasets that accurately describe the layers. The data that are critical for designing and analyzing hydraulic fracture treatments are in-situ stress, formation permeability, formation porosity, reservoir pressure, and Young's modulus. Many times, these parameters can be determined from logs and/or correlated to lithology.


Once the datasets are obtained, one can use a three-dimensional fracture propagation model to estimate values of created or propped fracture length, width, and height. To understand and improve the fracture design process, the engineer must confirm the estimates of fracture dimensions that are predicted by a fracture propagation model. To verify the model, one must analyze field data to be sure the field data are consistent with the model results. For example, the net pressure predicted by the 3-D fracture propagation model should closely match the net pressures observed in the field. When net pressure is adequately matched, we usually find that the overall created fracture dimensions predicted by a 3-D fracture propagation model are reasonable. To determine estimates of propped fracture length, one must also analyze post-fracture production and pressure transient data. Because of fracture fluid cleanup problems, we often find that values of propped fracture length generated by analyzing field production data are much shorter than the created fracture length predicted by the fracture propagation model. Detailed engineering studies are often required to reconcile the differences.


To directly measure values of fracture width, one must perform a fracture treatment in openhole, then use a downhole imaging tool to "see" the fracture. Such an approach is not usually pratical. In this paper, we will describe a method to qualitatively estimate the propped width profile at the borehole that uses radioactive tracers. Confirming the propped width profile generated by a model with field data can be very beneficial and informative.


We have found that the use of zero wash radioactive tracers can help us learn both (1) where the fracture fluid is going and (2) where the proppant resides in the fracture near the wellbore. Assuming the level of radioactivity is proportional to volume, then the level of radioactivity will also be proportional to the propped fracture width. As such, one can obtain qualitative estimates of propped fracture width at the wellbore using a radioactive tracer where the strength of the radioactive signal is proportional to fracture volume near the wellbore.


The objectives of this paper are to discuss what factors control the fracture width profile and how to obtain data to compute fracture width. We also explain how one can use radioactive tracers to develop data that can be analyzed to determine qualitative estimates of propped fracture width. Finally, we provide several examples to illustrate how one can estimate values can be used to calibrate a 3-Dimensional fracture propagation model.


The information described in this paper can be used by a production engineer to obtain a better understanding of a specific hydraulic fracture treatment. As our understanding of hydraulic fracturing improves, we should be able to design the optimal fracture treatment with more certainty. When we design and pump the optimal fracture treatment, we maximize the economic return on developing oil and gas properties.


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Radioactive Tracers Facilitate Stimulation Job Evaluation, Kevin Fisher, Ray Walker, Rob Dunleavy, Buddy Woodroof, Hal Crabb, Petroleum Engineer International, February 1995.


ABSTRACT

Radioactive Tracers Facilitate Stimulation Job Evaluation

Logging tools can now quantify multiple isotopes, including the volume of individual isotopes present and their radial position away from the well bore. In conjunction with those improvements, tracers have been developed that eliminate "wash off" effects of conventional tracers. By precisely locating the presence and concentration of traced proppant at the well bore, better evaluations can be made of vertical and radial proppant distribution near the well bore and fracture aperture width.


A comprehensive study of 98 wells with 136 fracture stages in four different basins has been completed. Each stage was traced and logged. Spectral gamma ray logs were compared with conventional openhole logs, sonic stress logs where available, and cased hole logs such as cement bond and production logs. This data was then compared on a well-by-well basis with the fracture design program, post treatment stimulation reports and production history.


Several trends were identified while building this massive stimulation evaluation database. Problems that potentially could be solved using tracer technology are:


• Fracture height greater than design.
• Unstimulated perforation sets within a stage.
• Understimulated pay intervals. 

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Using Low Density Tracers to Evaluate Acid Treatment Diversion, Mark Reid, David Holcomb, Kyle Waak, SPE 29587, March 1995.

ABSTRACT

Using Low Density Tracers to Evaluate Acid Treatment Diversion

Utilizing a newly developed low density zero wash tracer carrier (1.1 - 1.5 gm/cc), acidizing treatments performed across large gross intervals consisting of thinly laminated carbonate/sandstone reservoirs have been more accurately diagnosed with respect to placement efficiency. Multi-isotope tracer in combination with spectral gamma ray logs are used to evaluate and optimize acid treatments involving various diverting processes (i.e., rock salt/benzoic acid; ball sealers). Acid diverter treatments are evaluated using multi-tracer spectral gamma ray logs and subsequent efficiencies shown. A new low density tracer carrier that allows more effective, safer transport and placement of the isotopes was used and significantly improved the log interpretation. Example case histories of acid treatments evaluated using the new low density tracer carrier will be presented for treatments done in Utah, U.S.A.

Acid treatments performed in long multi-perforated intervals using various diverting techniques were shown to have different coverage distribution than expected or indicated by treatment pressures.

A new low density tracer carrier provides a clearer log definition where multi-isotopes are used to define acid stage and diverter stage distribution.


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Design, Execution and Evaluation of Acid Treatments of Naturally Fractured Carbonate Oil Reservoirs of the North Sea, Olivier Lietard, Jonathan Bellarby, and David Holcomb, SPE 30411, September 1995.


ABSTRACT

Design, Execution and Evaluation of Acid Treatments Of Naturally Fractured Carbonate Oil Reservoirs of the North Sea

This paper discusses all phases of the stimulation of naturally fractured carbonate, oil reservoirs in the North Sea.


The considered reservoirs are located in the vicinity of salt domes. Most of them are in the central part of the UK sector, east of Aberdeen. The reservoir rock is the well-known Tor chalk, whose mechanical properties have been greatly modified by the proximity of the diapirs. The matrix rock itself is much harder (more similar to a lime-stone) and the whole reservoir is fissured, particularly on the top of the dome. Double-porosity behaviour is usual.


Wells drilled through these reservoirs suffer from very severe damage due to the invasion of the natural fractures by large amounts of drilling mud and loss circulation materials. Stimulation consists of high rate damage removal treatments, alternating stages of crosslinked gel, customized acid formulations and ball sealers. Pre and post job well performances demonstrate huge productivity index increases due to the clean-up of the natural fissures around the wellbore.


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Improved Completion Designs in the Hugoton Field Utilizing Multiple Gamma Emitting Tracers, Mike Hecker, Mort Houston, Don Dumas, SPE 30651, October 1995.


ABSTRACT

Improved Completion Designs in the Hugoton Field Utilizing Multiple Gamma Emitting Tracers

Multiple gamma emitting tracers and post fracture spectral gamma ray logs were used to optimize production and improve the completion designs of 150 gas wells in the southwest Kansas region of the Hugoton Field. The information from the tracers and logs has revealed unstimulated pay zones and has been the impetus for completion modifications, yielding substantial gains in production. Through the use of limited stress barriers and permeability variations, perforation schemes have been successfully modified to improve fracture containment and proppant placement over the 200 ft Chase Group intervals. Previously these intervals were treated with multiple individual zone treatments.


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Measuring Hydraulic Fracture Width Behind Casing Using a Radioactive Proppant, J.C. Reis, Kevin Fisher, David Holcomb, SPE 31105, February 1996.


ABSTRACT

Measuring Hydraulic Fracture Width Behind Casing Using a Radioactive Proppant

Knowing the width of a hydraulic fracture behind casing can be useful in evaluating both reservoir performance and fracture design methods. This paper presents a method to obtain the widths of hydraulic fractures behind casing using radioactive, isotope-traced proppants. A tool-specific relationship between the gamma-ray flux detected in a wellbore and the fracture width was developed using Monte Carlo stimulation of gamma ray transport around a wellbore. This method provides fracture width estimates with a vertical resolution of about one foot. The method has been successfully used in the field and compares favorably with other methods for evaluating fracture widths.


 

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Using Tracers for Monitoring and Diagnosing Horizontal Well Stimulations, David Holcomb, Robert A. Woodroof, World Oil Horizontal Well Completions Symposium, 1996.


ABSTRACT

Using Tracers for Monitoring and Diagnosing Horizontal Well Stimulations

The application of multiple radioactive tracers (Zero Wash®) and spectral gamma ray imaging has allowed for improved diagnostics of stimulation treatment distribution. Whether acidizing and diverting or fracturing and proppant placement, multiple tracers (i.e.; Iridium-192, Scandium-46, Antimony-124) have allowed operators to better analyze proppant entry with respect to stage, volume, and/or type placed across lateral intervals, as well as acid entry and distribution in order to better understand and optimize treatment techniques such as diverting, rates, stage sizes, etc.


Holcomb and Read demonstrated that tracers were useful in evaluating Austin Chalk and Bakken Shale completions in South Texas and North Dakota respectively. Qualitative comparisons helped operators understand stimulation coverage and diversion effectiveness.


Problems still plague the use of tracers in horizontal wells and usually center around uncemented or poorly cemented casing. Tracer materials can accumulate behind pipe in depressions or washed out sections even if acid or slickwater treatments are overflushed. While this may make tracer images more difficult to interpret, it does not rule out their usefulness for identifying potential problem areas. Open hole horizontal completions have also posed problems for tracers due to wash-off of tracer materials and adsorption onto rock, not necessarily associated with fracture entry. Improvements made in horizontal well drilling and completions have been aided by the reliability of improved Zero Wash® tracer carriers and spectral imaging tools to provide a more quantitative look at stimulation treatment placement across horizontal well sections without the problems associated with wash-off and subsequent adsorption onto rock, casin, liners, etc.


One particular application has been noted with tracers used to confirm the success or failure of various diverting techniques to allow lateral zones to be completely acidized. Different Zero Wash® tracers are placed in different stages of acid separated by various diverter stages using such materials as oil soluble resins, gel pills, ball sealers, benzoic acid, rock salt, crushed Unibeads®:, or foams. Three tracers are usually used in a variety of carrier sizes, densities, and non-wash/crush/abrasion-loss formats. They include Iridium-192, Scandium-46, and Antimony-124, with half-lives varying from sixty to eighty-four days.

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Application and Evaluation of Advanced Completion Optimization Technology in the Black Warrior Basin, Bob Barba, Buddy Woodroof, SPE 36673, October 1996.


ABSTRACT

Application and Evaluation of Advanced Completion Optimization Technology in the Black Warrior Basin

The Black Warrior Basin continues to be an active area for development of coalbed methane in spite of the expiration of the Section 29 tight gas tax credit. The majority of the successful wells have been in areas with relatively high permeability, with mixed results in low permeability areas. A study was initiated in late 1995 to determine if stimulation results could be improved in these areas by implementing specific optimization procedures for each of the coal groups. The optimization process involved extensive prefrac formation evaluation, injection/falloff testing, in-situ stress testing, fracture modeling using a P-3D simulator, perforating small intervals with 45 degree phased to minimize multiple fractures and tortuosity, intense quality control onsite prior to and during the jobs, estimation of spurt loss by pumping dual minifracture treatments, fracture height control by limiting rate and viscosity, real-time P-3D modeling of minifrac and main frac treatments to obtain tip screenouts, radioactive tracing of individual fluid and proppant stages with time-lapse monitoring, and postfrac history matching of job results. The real-time fracture modeling involved monitoring bottomhole pressures using a live annulus after comparison to data from a remote telemetry system and a quartz gauge on the initial well. Several practical innovations were developed during the study that will aid in designing the optimum treatment for each well.


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Integrated Reservoir Fracturing and Completion Study to Maximize Productivity of Individual Niobrara Wells in Yuma County, Colorado, R.E. Blauer, B.D. Brady, D.L. Holcomb, F.L. Robinson, SPE 36469, October 1996.


ABSTRACT

Integrated Reservoir Fracturing and Completion Study to Maximize Productivity of Individual Niobrara Wells In Yuma County, Colorado

Consistently and continuously applied fracturing, reservoir and production engineering used to increase recovery from a original production low-permeability and low-pressure dry-gas reservoir has approximately doubled the initial production rate and the estimated ultimate recovery expected from new wells. The on-going costs of the additional engineering and technology to sustain the increased productivity of this reservoir is a few cents per MCF. As a result, new wells can be drilled and produced economically, the selection criteria for acceptable infill and exploration locations is greatly expanded, and proven gas reserves for both the new wells and the region are increased. Significant performance improvement can be achieved using a minimum number of wells, consistently collected data, and continuous review of performance changes caused by completion procedures changes. Exploitation optimization is an evolutionary process, not a one time study.

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The Application of Hydraulic Fracturing Models in Conjunction with Tracer Surveys to Characterize and Optimize Fracture Treatments in the Brushy Canyon Formation, Southeastern New Mexico, Ray Johnson, Buddy Woodroof, SPE 36470, October 1996.


ABSTRACT

The Application of Hydraulic Fracturing Models in Conjunction with Tracer Surveys to Characterize and Optimize Fracture Treatments In The Brushy Canyon Formation, Southeastern New Mexico

In this study of the Brushy Canyon Formation, sonic-derived, rock-mechanical properties and bottomhole treating pressure (BHTP) data from fracture treatments will be history-matched with a fully three-dimensional (3D), a lumped 3D, and a pseudo 3D fracture model. Height dimensions obtained from these history-matches are compared with temperature and radioactive tracer surveys to better characterize fracturing mechanics in this Delaware Mountain Group formation. Cases will be presented from Eddy and Lea Counties in southeastern New Mexico.


 

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Pressure Transient Data Acquisition and Analysis Using Real Time Electromagnetic Telemetry, L.E. Doublet, J.W. Nevans, M.K. Fisher, R.L. Heine, T.A. Blasingame, SPE 35161, March 1996.


ABSTRACT

Pressure Transient Data Acquisition and Analysis Using Real Time Electromagnetic Telemetry

This paper presents the operational procedures and the results for two pressure buildup tests performed using a wireless telemetry acquisition system (TAS) tool at the Northern Robertson (Clearfork) Unit (NRU) in Gaines, Co. Tx. Using a single pressure gauge system downhole, we obtained real-time telemetry of pressure and temperature data at the surface, as well as a larger sampling of data that were stored in the downhole memory system.


This new wireless telemetry acquisition system was developed to provide real-time pressure and temperature data at the surface by using an electromagnetic signal to transmit these data through the formation strata. The tool is fully programmable so that a wide range of sampling frequencies can be used. The system allows pressure and temperature data to be stored downhole (as in the case of a typical "memory" gauge), or these data can be transmitted to surface data acquisition systems. This provides real-time pressure and temperature data for pressure transient tests, stimulation monitoring, and long-term reservoir surveillance.


Our objective is to demonstrate the use of this technology for pressure buildup tests in low permeability reservoirs. Our goal in utilizing this technology is to reduce the shut-in time requirements for pressure transient tests, which will ultimately result in a more cost-effective reservoir surveillance program as wells can be returned to production (or injection) as quickly as possible.


Once the pressure data were acquired, we performed conventional semilog and log-log analysis, and we simulated test profiles to verify the analyses of the test data. Both surface and downhole pressure data were compared for consistency, and both types of data were analyzed in exactly the same fashion. The results of these analyses were essentially identical. This approach gave consistent estimates of reservoir pressure, permeability, skin factor, and fracture half-length for both of our case histories.


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Wireless Telemetry for Transmitting Pressure and Temperature Data on a Drillstem Test, Kent Holder, Dick Heine, David Copeland, SPE 35241, March 1996.


ABSTRACT

Wireless Telemetry for Transmitting Pressure and Temperature Data on a Drillstem Test

An openhole drillstem test (DST) simulates producing conditions to help operators determine if a formation may be commercially productive during the drilling phase of the well. A DST isolates a formation with packers, and a tester valve opens to expose the formation to lower hydrostatic, which causes the formation to produce. After a predetermined flow period, a downhole shut-in valve closes to start a buildup period. The sequence of flow and closed-in periods is repeated as required.


Testing can provide information such as effective permeability, skin damage, formation pressure, flow rate, fluid type, and radius of investigation. Effective permeability, skin damage, and formation pressure calculations are possible only if the buildup period is long enough to reach Horner data. The duration of close-in periods is generally based on rule of thumb, bubble-hose response, or field experience. Surveys of current DST reports indicate that 30% of formations tested were not shut in long enough for Horner data to be obtained. The best method to determine the length of flow and shut-in periods is to monitor the pressures real-time at the surface. Wireline surface readout is available but is costly and poses risks, since the wireline is in the well.


 

Once the pressure data were acquired, we performed conventional semilog and log-log analysis, and we simulated test profiles to verify the analyses of the test data. Both surface and downhole pressure data were compared for consistency, and both types of data were analyzed in exactly the same fashion. The results of these analyses were essentially identical. This approach gave consistent estimates of reservoir pressure, permeability, skin factor, and fracture half-length for both of our case histories.


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Optimizing Artificial Lift Operations Through the Use of Wireless Conveyed Real Time Bottom Hole Data, Bryan Campbell, James MacKinnon, Thomas R. Bandy, Tom Hampton, SPE 36596, October 1996.


ABSTRACT

Optimizing Artificial Lift Operations Through the Use Of Wireless Conveyed Real Time Bottom Hole Data

The use of an innovative wireless bottom hole pressure/temperature telemetry acquisition system in artificial lift operations can dramatically improve efficiency and optimize fluid producing rates in those wells. The tool is installed into the producing well in the vicinity of the perforations, measuring and transmitting the producing bottom hole pressures and temperatures to the surface for instantaneous control of the surface pumping motor speed. This insures the lowest possible fluid level back pressures, thus allowing for the highest possible fluid entry into the wellbore from that reservoir's capacity. Operating costs per barrel are lowered since the maximum oil production can now be realized from existing wells.


The telemetry tool is deployed with standard slickline equipment and is installed inside a well in a manner similar to ordinary pressure recorder tools. Several unique advantages of the tool are:


1. no moving parts
2. no wireline to the surface
3. real time measurements of bottom hole data
4. slickline retrievable.

Future versions of the acquisition system tool will improve operating efficiency in the following ways:


• Temperature monitoring and control of perforation scaling, tubular waxing. And tubular hydrating plugs.
• Provide data necessary to create diagnostically predictive IPR curves through monitoring of reservoir in-flow rates.
• Enabling early warning of water encroachment or lensing through fluid resistivity monitoring.

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Real-Time Bottomhole Data Can Improve Accuracy of Fracture Diagnostics, Kevin Fisher, Earuch Broacha, GRI GasTips Volume 3, Winter 1996/1997.


ABSTRACT

Real-Time Bottomhole Data Can Improve Accuracy of Fracture Diagnostics

Much time and effort is spent today in an attempt to better understand the hydraulic fracturing process. With the wider application of Advanced Stimulation Technology (AST) for example, three-dimensional (3D) fracturing models have become much more common, many of the capable of performing simulations in real time (see article in Spring 1996 issue of GasTIPS, "Fracturing Practices Influenced by GRI Technologies"). However, a rigorous numerical simulation requires accurate bottomhole pressure and temperature data. These data are seldom measure and the majority of the time must be estimated from surface treating data.


Gas Research Institute (GRI) has helped develop a system for measuring bottomhole data in order to improve and expand the application of AST.


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Strategic Alliance, Multidisciplinary Teamwork Enhance Field Development in Cotton Valley Trend, Holly Krus, Larry Brit, Kevin England, Nick Piskurich, Robert A. Woodroof, Oil and Gas Journal, March 31, 1997.


ABSTRACT

Strategic Alliance, Multidisciplinary Teamwork Enhanced Field Development in Cotton Valley Trend

A strategic alliance and multidisciplinary teamwork improved economic performance of a field in the East Texas basin's Cotton Valley trend.


Optimizing the development phase, and thus improving the profitability, of Amoco Exploration & Production Co.'s Glenwood natural gas field was the task assigned to a multidisciplinary reservoir management team (RMT) in 1996. The team comprised personnel from Amoco, Schlumberger companies Dowell Wireline & Testing and GeoQuest, and ProTechnics International.


Members were chosen largely from an existing Amoco/Schlumberger strategic alliance that had been in place for 4 years. The team's primary emphasis was to strategically locate and fracture-stimulate the remaining wells to be drilled in Glenwood field's initial development phase.


This article illustrates the team process used and decisions made that let to field cost savings and production improvements before yearend 1996. Thorough data collection and evaluation were critical project elements and enabled the field's hydraulic fracturing program to be modified, thus improving incremental production and eliminating ineffective fracturing costs.


 

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Real-Time Analysis on a Drillstem Test Using Wireless Telemetry, Kent Holder, Halliburton Energy Services, Dick Heine, ProTechnics, Doug Perschke, Marathon Oil Co., Southwest Petroleum Short Course1997.


ABSTRACT

Real-Time Analysis on a Drillstem Test Using Wireless Telemetry

The openhole drillstem test (DST) has changed little in the last 30 years; however, pressure-transient analysis recently has made significant advancements. Modern electromagnetic telemetry systems are the basis for an economical method of transmitting pressure and temperature readings in real time. Improvements in information technology now allow advanced on-site analysis. This paper provides an overview of an openhole test, describes the components used during real-time analysis, and discusses the case history for a real-time job in Andrews County, TX.


The openhole test is a common method of formation evaluation that is most often used during the drilling phase of the well. To determine reservoir content, downhole tools allow a zone of interest to produce. Downhole gauges record changes in pressure during the test, providing data that later can be analyzed to determine reservoir characteristics. Designing and performing a conclusive test is difficult when key reservoir parameters, such as permeability, reservoir description, and bottomhole pressure, are not known. On a standard test, the operator must wait until the tools are retrieved before:


• determining if the test was mechanically successful
• analyzing the data
• determining if the test was conclusive
• determining the next step for the well

Real-time data analysis allows the operator to conduct a conclusive test, analyze the data, and determine the next step, often before the tools are out of the well. The time saved by analyzing the data in real time reduces rig costs and provides owners with more time to review the well data.


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Methodology to Optimize Completions in the Mesaverde Formation, San Juan Basin, New Mexico, Brian P. Ault, Burlington Resources; Earuch F. Broacha, and David L. Holcomb, ProTechnics International, Inc., , SPE 38580 October 1997.


ABSTRACT

Methodology to Optimize Completions in the Mesaverde Formation, San Juan Basin, New Mexico

Results of a recent major field study are used to define the optimum stimulation method of the layered, low permeability, naturally fractured Mesaverde formation in the San Juan Basin of New Mexico. Several stimulation methods are discussed and evaluated with respect to reservoir properties, production response, specific treatment characteristics, and well economics. The field study focused on the following objectives:

1. The development of stimulation treatment methods for geographic areas where production is controlled by extensive natural fracturing.
2. Creating a method for determining the degree of natural fracturing present in any particular well location utilizing only historical production and pressure data.
3. Determine if a well can be economically stimulated to drain the Mesaverde reserves on existing well spacing at the current gas pressure.
4. Assess the effectiveness of various treatment diagnostic tools, such as radioactive tracers and pressure monitoring, in the evaluation of fracture efficiency, geometry, proppant placement and distribution as well as possible communication between stages, and the percentage of each pay interval stimulated.

INTRODUCTION

The Mesaverde Group (Point Lookout, Menefee, Cliffhouse intervals) was deposited in the Upper Cretaceous period and is present throughout many of the Rocky Mountains basins. This study focuses only on Mesaverde in the San Juan Basin of New Mexico (Figure 1). The Estimated Ultimate Recovery (EUR) for the Mesaverde in the San Juan Basin is approximately 13 trillion cubic feet (TCF) of natural gas, making it the second largest gas field of the United States. Since 1950, approximately 8.6 TCF has been produced from the Mesaverde. Currently there are 5,100 Mesaverde wells producing a total of 600 million cubic feet of gas per day (MMCF/D). There are 1.8 million productive acres of Mesaverde in the San Juan Basin.


The field study was initiated due to the difficulty in relating producing well behavior to open hole log analysis in the Mesaverde. Wells with very similar log responses had extremely variable cumulative production histories. A study was therefore outlined to investigate the relationships between reservoir quality, type of completion, and well performance.