highlights of workshops

2004-2007

 

Gas Reservoir Evaluation with Limited Data
(August 8, 2007)

This presentation, based on material from a senior-level petroleum engineering course, dealt mostly with the theory behind equations used to evaluate physical properties of petroleum fluids. Commercial packages exist for tedious data handling and fitting functions, but less expensive spreadsheet tools are also available.

Estimating a reservoir’s initial supply of gas and predicting how that supply is being depleted is termed reservoir performance. Assumptions and limitations of the following approaches for determining the performance of gas reservoirs were discussed.

  • Volumetrics (geological/geophysical maps) coupled with empirical recovery factors
  • Material balance calculations using PVT data to reflect recovery behavior
  • Decline analysis
    • Production rate vs. time. NOTE 1: Parameter units must be consistent. E.g., a flow rate of MCF/day must have time/decline units in days. NOTE 2: Fit appropriate curve type to data – exponential, harmonic, hyperbolic, anomalous.
    • Fetkovitch-style type curves using constant pressure solutions to the diffusivity equation
    • Material balance time approaches

 

Converting surface measurements of volume, composition and flow rate to reservoir volume, composition and gas flow rate results in a better understanding of the reservoir. For economic determinations, it must be remembered that price, typically listed as $/MMBTU, is based on heating value of the gas being sold and is not exactly equivalent to $/MSCF of “gas”.

An aid to obtaining data when information is limited can be found at http://members.cox.net/rghconsulting/OGS080807.htm. A free Microsoft Excel add-in to estimate PVT properties for oil, gas, and water using empirical relationships is given. (NOTE: The add-in uses temperatures in ºF but thermodynamic equations use º Rankin.) Pay particular attention to the “range of validity” for each listed function. Code to compile routines for calculating the Cullender & Smith factor and friction factor to interface with the PVT add-in is given also. 

 

The following workshops were co-sponsored through the Department of Energy's Petroleum Technology Transfer Council (PTTC) program between 1994 and 2007.

Produced Water Issues and Casing Leak Prevention and Repair

(February 2007)

Produced Water Issues

In 1999, the world’s production of oilfield water was three times the volume of produced oil. In the United States, 91% of produced water is reinjected, 70% for waterflooding or pressure maintenance and 21% for disposal. Water handling/injection is the single biggest operating cost in mature fields.

The produced water part of this workshop centered on information taken from a manual developed as a resource for independent operators.  Characteristics of reservoir drive mechanisms --- solution gas, solution-gas-gas-cap, and water --- were discussed along with the effect each mechanism has on water production and pressure. Collecting well and production data and then plotting that data enables the producer to better visualize what is happening with a well. Among completion and stimulation options, a solid propellant stimulation technology known as TheGasGun was described in detail. Several wireline companies in the Midcontinent are licensed to offer it. Case studies from Kansas indicate a 2-3 fold increase in oil production with its use.

Gelled polymers can be applied as a matrix gel to shut-off water near the wellbore or used as a fracture gel to increase sweep efficiency far from the wellbore in waterfloods. Recent improvements in the process provide greater control of gelation time (from a few hours to weeks) and wider, deeper placement volumes. Changing polymer type, gel concentration, polymer volume or injection rate during treatment is easily accomplished if and when the pressure response so indicates. A successful treatment still depends mostly on experience. Empirical methods suggest treatment size should be:

  1. at least two times the well’s daily production. (For lower fluid level wells, daily production is the minimum.)
  2. daily production capacity at maximum drawdown.

 

Details of candidate well selection, well preparation prior to treatment, placing the treatment (monitoring pressure response), what to do after treatment, re-treatment when production levels off, and potential problems (often corrosion-related) were presented. Case studies from different types of reservoirs in Kansas, Oklahoma, and west Texas were given. Based on average values from 300 polymer treatments in Kansas, the average payout was ~7 months when considering only incremental oil. Taking into account lower lifting costs resulting from reduced water production would improve this figure.

In starting a waterflood, the most important but difficult decision for an operator to make is to get the water where the oil is. That often means the best injector well is the best producing well.

Casing Leak Prevention and Repair
Maintaining casing integrity requires controlling corrosion. Corrosive agents in the oilfield include carbon dioxide, hydrogen sulfide, oxygen, and microbes; other factors causing steel corrosion are chloride, temperature, pressure (indirect), velocity, and wear/abrasion. The benefits of rectifier, alternator, and solar types of cathodic protection were discussed. Corrosion inhibitors, which can be oil soluble, water soluble, oil soluble but water dispersible, or volatile, are applied in batch mode, continuous mode, or as a squeeze. Tips for selecting and applying inhibitors were given.

Corrosion is measured with weight loss coupons, linear polarization resistance, electrical resistance, or iron counts. The advantages and disadvantages of these methods were evaluated according to:

  • Ease of installation                                   
  • Place of measurement
  • Directness of measurement                       
  • Equipment needs
  • Visibility of measurement                          
  • Extent of measurement
  • Cost                                                        
  • Reaction to sour environment
  • Real-time vs. time-average result              
  • Need for other data

The best advice is to keep complete records and not rely on a single method but use several techniques simultaneously.

Pressure testing and casing inspection logs detect and identify problems. MicroVertilog uses magnetic flux anomalies to differentiate between internal and external tubular defects. Well preparation techniques for using UltraSonic or Multifinger Imager Tools were presented. Downhole video inspection requires wellbore fluid to be clear and transparent.

Repair options covered were expandable tubulars, casing patches, and squeezes --- polymer, combination, and cement. Examples described in detail were MetalSkin® - a new generation of expandable cased-hole liner and HOMCO internal steel casing patches – inserted as a corrugated configuration but then set (expanded) to tubular. There are three types: standard – rated at 325°F.; high temperature – rated at 600°F.; and corrosion resistant stainless steel. They can be run through a previously  set patch. Unwanted perforations, splits or leaks can be sealed in one trip.

Cement squeezing is basically a filtration process. The slurry, subjected to differential pressure against a filter of permeable rock, loses water, leaving a cake of partially dehydrated cement particles. Intermittent pressure application separated by periods of pressure leakoff is referred to as hesitation squeeze. A squeeze job is complete when the surface pressure does not bleed off after pumping is stopped or there is a lack of pressure leakoff at a pressure 300–500psi higher than the final injection pressure. Step by step procedures for both low and high pressure techniques, including evaluating the success of the job, were outlined.
           

Oklahoma 3-D Seismic Applications

(November 2006)
(Workshop manual available as OGS Open File 7-2006.)

The use of 3-D seismic to image subsurface rocks increases geologic knowledge, improves drilling accuracy, and lowers risks in exploration. But is it worth the cost? In discussing the application of seismic technology to specific oil and gas plays in Oklahoma, four speakers noted that every basin, with its unique trapping and drive mechanisms, requires an individualized approach to avoid potential pitfalls. Occasionally 3-D seismic data is limited, either horizontally or vertically.

Basic tools used to acquire geophysical data include:

  • acoustic sources - explosives, vibroseis trucks, air guns (for marine or lake acquisition)
  • equipment - buggy drills or heli-portable drills (for rugged or environmentally sensitive areas)
  • geophones (dry land) or marshphones (wetland)
  • recording vehicle (with electronic, computer, and diagnostic devices)

The size of a survey depends on depth objective, lease position, available funds, and complexity of subsurface (e.g., dipping event) geology. The pattern in which sources and receivers are laid out is used to optimize the way sound waves hit the reflectors. Recommended recording geometries account for offset (distance that a trace travels from source to detector) and azimuth (direction that a trace travels from source to detector). Modern techniques using multiple frequencies can be used to determine reservoir properties such as porosity, permeability, saturation, stress, and pore pressure.

Processing seismic reflection data makes the data easier to interpret. This topic was addressed by defining and explaining processing terminology, such as static shifting (makes it appear data were recorded from the same elevation); noise filtering (reduces noise to signal ratio); averaging and/or stacking traces (increases signal to noise ratio); and migration (corrects for misrepresentation of reflector position).

The 14 Oklahoma plays selected for detailed geologic and geophysical discussion are:

  • Old Woman Channel, Watonga-Chickasha Trend
  • SE Gage Field
  • Cyril Area, NE Fletcher Field
  • Cement Field
  • Deep Red Fork Sand, E Clinton Field
  • Deep Atoka Carbonate Wash, Berlin Area, Carpenter Field
  • Hunton Structure, W Arlington Field
  • Skinner Sand, NW Sooner Valley Field
  • Hartshorne Sand Channel, S Pine Hollow Field
  • Paleozoic Structure, Fitts Field
  • Spiro Sand and Arbuckle Dolomite Structure, Wilburton Field
  • Ouachita Overthrust, Buffalo Mountain Field
  • Paleozoic Structure Simpson Play, W Whitebead Field
  • Paleozoic Structure, Cumberland Field

Caney Shale Gas Workshop

(August 2006)

With 1/3rd of the United States's natural gas supply projected to be tied up in gas shales by 2014, gas shales have been termed the next "big" onshore play in the United States. Once viewed only as source rocks, organic-rich shales are now receiving attention as reservoir rocks. How to better understand these rocks and gain access to their valuable hydrocarbon resource was the main theme of this workshop, with special emphasis given to the Caney Shale in Oklahoma.

The Mississippian-age Caney is geologically equivalent to the Barnett Shale in north Texas and the Fayetteville Shale in Arkansas. In an overview of the Caney, the first of six speakers stepped through the tectonic changes and subsidence history that led to present day distribution of the Caney. In the Arkoma Basin, the main area of interest, the Caney is stratigraphically uniform, thickening only where stacking of thrust sheets aggregates the layers. Throughout Oklahoma there are 58 Caney (frequently reported as "Mississippian") gas shale wells, including 9 horizontal.

Isopach maps of 6 Caney Shale subdivisions were described for a 22x9-township region extending from central Oklahoma into the deep Arkoma Basin. Vitrinite reflectance and Tmax measurements show the Caney is a very cooked rock. Basin modeling indicates it went through the oil window before the end of the Pennsylvanian, with later heating cracking the oil to gas. Acid treating is preferred over fraccing to create porosity. A preferred horizontal well profile involves first setting pipe in an angled sump hole and then kicking off laterals. "Mining" information from logs can be worthwhile. Plotting Vp/Vs ratios from sonic logs - a "poor man's seismic turned on its side" - vs. neutron density, gas saturation, and bulk water porosity can help differentiate between water-wet and gas-bearing shales. This idea is based on the intrinsic acoustic anisotropy of shales. Processing signals of gamma ray logs through wavelet analysis is a possible approach for measuring sedimentation rates.

An important technological advance in gas shale exploration, in addition to improved fracturing techniques and horizontal drilling, is the use of geochemical data to delineate productive zones. Geochemists define and measure quantity of TOC (total organic matter), type of organic matter (kerogen), thermal maturity, free gas vs. sorbed gas, and stable isotopes to help predict prospective areas for the explorationist. Details of these measurement processes and their limitations were summarized by the third speaker.

Evaluation of a shale gas reservoir involves delineating the bed, quantifying adsorbed and free gas, determining producibility of the system, and predicting production. Computerized wireline evaluation techniques can perform these tasks. Based on a set of interpretation models, the software solves simultaneous equations using data from downhole logs. The speaker discussed applying the program to solve for adsorbed and free gas content (GIP) as well as generating input for frac designs and production simulators.

The two most important messages from a talk on horizontal drilling were that horizontal directional drilling expertise is area specific and extensive pre well planning between client and drilling company is required. Other topics included well design options, how the accuracy of survey tools affects wellbore uncertainty, bottom hole assemblies, rig requirements, lateral length (Generally, 2000 feet or less is the best risk even though longer lengths generate more excitement.), and new technology. A formation boundary detector that looks at formations ahead of and around the bit sounds promising.

Older Caney production in Oklahoma is from vertical wells but more recent completions are horizontal. As with the Barnett, cased cemented multi-stage fracs are the predominant completion method. The number of frac stages used in the Caney is 3 or 4. Other completion types common in the Barnett have not yet been applied to the Caney. The use of reactive stimulation fluids in place of conventional water frac treatments appears to significantly increase initial production in the Caney.

Fayetteville Gas Workshop

(May 2006)

A fast-paced presentation on applying organic geochemistry to understanding shale gas systems addressed such topics as:

  • Amount of organic matter present in the rock matrix. Total organic carbon (TOC) measures the quantity of carbon (C) but not all of that can be converted to hydrocarbons, a process that requires hydrogen as well. Only "live" C has generation potential remaining, whereas dead/inert C can serve as an adsorption site. Adsorption helps explain the high volumes of gas in some shales. The Fayetteville Shale, already cooked out, has no more generation potential. Both its Rock-Eval Tmax (measure of maturity) and S2 peak (measure of remaining potential) are useless.
  • Maturity level of organic matter. This parameter can be determined by vitrinite reflectance, gas chromatographic identification of decomposition products, and Rock-Eval pyrolysis. High-maturity shale gas, such as the Fayetteville, generally has a high flow and fast depletion rate.
  • Type of organic matter (kerogen). The nature of the original biomass material determines whether its conversion will result in more oil-prone or gas-prone hydrocarbons.
  • How decomposition of organic matter can help to increase porosity.

Although about 2 million acres have been leased, there is little production (~2 BCF/yr) from the Fayetteville. Infrastructure is not yet in place for the level of activity expected. Jointing of outcrops and directions of stress indicate the Fayetteville will frac well in the subsurface. A nitrogen foam frac has been used; more slick water fracs may be tried. One hundred million gallons of water is required to do a horizontal frac but there are no close disposal wells at the current time. From their studies (available as AGC Information Circular 37), the Arkansas Geological Commission has prepared maps of the three main areas of the Fayetteville Shale gas play, showing locations of all holes drilled, permits for vertical and horizontal wells, transmission lines, and field boundaries. Using TOC and vitrinite reflectance data, they modeled the eastern and central portions of the play. Vitrinite values of 1.9-5.0% suggest the exploration target — Lower-Middle part of the Fayetteville sequence — is dry gas only. In response to questions, it was noted that the deeper Boone could be a valuable secondary conventional target. The Chattanooga has good TOC and sufficient maturity but, except for Lee County, is too thin a reservoir.

The Arkansas Oil & Gas Commission (AOGC) is currently working on regulations geared to anticipated production from the Fayetteville Shale. A Proposed General Rule B-43 deals with spacing of Fayetteville Shale wells, among other issues related to "unconventional sources of supply". Based on this despacing, which permits up to 25 wells per established drilling unit, AOGC projects 750 producing Fayetteville wells by 2009.

Coalbed Methane and Gas Shales in the Southern Midcontinent

(March 2006)

This one-day conference, the nineteenth in an annual series devoted to hydrocarbons in the southern midcontinent, drew a record attendance of 392 people from 13 states and Canada. Not only is coalbed methane (CBM) still a hot topic, but the success of the Barnett Shale in Texas as a gas play has generated much interest in the potential of the Fayetteville, Woodford, and Caney shales in nearby states.

An explanation of the Oklahoma Corporation Commission’s approach in trying to apply exisitng regulations formulated for conventional oil and gas wells to the special circumstances presented by CBM wells was followed by four papers dealing with CBM:

  • Production trends in southeast Kansas. Plans are underway to investigate the feasibility of injecting a combination of landfill gas and coalbed gas into a coal seam to both sequester the CO2 and enhance the release of more methane.
  • Oklahoma update.  In 2005, 96% of Arkoma Basin CBM wells were horizontal. Laterals have averaged 2000 ft. but in one case extended over a mile.
  • Completion techniques for wells in 3 Osage County case studies. Horizontal laterals are preferred where one encounters surface limitations (housing developments, lakes, etc.) or low perm coals that could not withstand fracture stimulation.
  • Recommendations for drilling horizontally in Arkoma Hartshorne Coal. Follow the gamma-ray reading (e.g., “up” if 15/20 and “down” for 21/14), orient the well updip and perpendicular to the face cleat and major fracture planes, be on the lookout for faults, and prepare a post drill summary.

The Upper Mississippian Fayetteville Shale stretches across Arkansas from east to west, with the central section the most active as a gas shale play. Total organic carbon and vitrinite reflectance results from 43 wells were used to model thermal maturity in the pay zone.

Gamma-ray profiles and lithofacies descriptions of 5 outcrop samples of Woodford Shale in south-central Oklahoma were used to characterize the Woodford in the subsurface.

Papers on the Caney Shale addressed:

  • Stratigraphy and log character, comparison with the Woodford in outcrop, and production decline curves for oil and conventional gas from Caney wells.
  • A study of well logs from a 132 x 54 mile area in southeastern Oklahoma, organic carbon, vitrinite reflectance, and gas desorption data to divide the Caney into members A – F. The D zone was found to have the most hydrocarbon potential. Gas show data from mud logs alone supplied a fairly close estimate of gas-in-place.
  • Thin section analysis of samples from 8 townships in the western Arkoma Basin. Bands of calcite as well as separated regions of sorbed and non-sorbed calcite were detected. Acid is the recommended fracture treatment for the sorbed calcite.

Cyclic stratigraphy and conodont biostratigraphy revealed 3 faunal intervals in the Barnett. Conodonts in the top interval are early Morrowan, not Mississippian. Preliminary correlation work suggested the Caney is a different age from the Barnett.

An abbreviated mini course on the application of organic geochemistry to exploring for and developing shale gas included appraisal results for several basins, with an emphasis on the Barnett Shale in the Ft. Worth Basin.

Surface reactive fluids appear to improve shale gas production by removing acid-soluble minerals in the bulk shale and in calcite-filled micro-fractures.

Poster sessions topics not covered in talks centered on thermal maturity of the Woodford Shale, coal rank and coal nomenclature in Oklahoma, CBM recovery from U.S. basins, and determining downhole critical gas content – without core.

 

Booch Gas Play in Southeastern Oklahoma (December 2005)

The Booch stratigraphic interval in eastern Oklahoma extends from the Kansas border on the north to the Choctaw Fault on the south. However, the Booch gas play, which accounts for 70% of cumulative and current Booch production, lies within the limits of the Arkoma Basin .

 

Thick, somewhat immature Booch marine shales, containing gas-prone kerogen and 3-18% TOC, are thought to be the source of most Booch gas. The lower thermal maturity of the shales may explain the underfilling of the gas reservoirs. Reservoirs in the Booch gas play are significantly underpressured, requiring compression early in the life of producing wells. Stratigraphy is the key trapping mechanism, although faults and structural closures are important. The Booch formation is shallow and cheap to drill. Risk is manageable due to abundant well control; and the prolific Hartshorne lies just beneath the Booch, offering an attractive secondary objective.

 

This study was designed as a starting point for those interested in pursuing Booch natural gas. Conclusions presented were based on a widely spaced data grid, using well-log and core data to construct 9 regional cross sections. Field studies of Texanna SW (part of the large Brooken Field), Reams SE, and Pine Hollow South were chosen to illustrate production from different parts of the Booch. A special feature of the program covered drilling and completion practices used by a long-time Booch operator. He prefers air drilling for Booch gas in the basin and mud drilling for oil prospects on the shelf.

 

Artificial Lift - Downhole Technology and SPCC Rules and 2002 Revisions (August 2005)

(This was a double-header program developed in response to requests from operators in south Arkansas .)

Artificial Lift - Downhole Technology

Ninety percent of wells worldwide use some form of artificial lift. This presentation consisted of an overview of artificial lift technology followed by a detailed look at reciprocating rod lifts, the industry standard for applications on land. The six basic types of artificial lift are:

• Reciprocating rod lift - efficient, easy to repair/service, flexible, high salvage value for equipment

• Electric submersible pump - excellent for offshore

• Progressing cavity pump - handles deviated wellbores with minimal surface requirements

• Gas lift - excellent for offshore

• Plunger lift - ideal for wells that load up with produced wellbore fluids, easily serviced, economic

• Hydraulic lift - good for high-volume, high-depth environments

There are also hybrid systems, which combine the strengths of different types to increase efficiency and improve economics.

The discussion of reciprocating rod lifts covered the overall design and operation of the technology, including both tubing pump and insert pump models. Instructions were given in how to "read" API nomenclature to determine pump features or sucker rod dimensions. Both strengths and limitations of various sucker rods - continuous and coupled, metallic alloy and fiberglass - were addressed. Advantages and disadvantages of using sinker bars and rod guides were explained. The most common reasons for pump failures are operational (e.g., bad seating nipple, loose tubing anchor), well condition (e.g., fluid pound, sand), or mechanical (e.g., split barrels, make-up torque) problems. Improper joint make-up is the leading cause of sucker rod failures. Time and money spent in optimizing pumping units to reduce failures will payoff in less than six months.

The presentation ended with a brief look at surface equipment.

SPCC Rules and 2002 Revisions

In August 2002, the EPA revised the rules in 40 CFR 112.1 through 112.21, which deal with the Spill Prevention, Control, and Countermeasure Plan (SPCC). SPCC regulations detail procedures, steps, equipment, and workforce needed to prevent, control, and provide adequate countermeasures to an oil discharge. This workshop provided an explanation of existing SPCC requirements, clarification of definitions of terms, time frames for compliance, and outstanding issues EPA has yet to resolve --- all in language an ordinary person could understand.

The presenter had practical information about how the EPA defines terms and how their inspectors enforce rules and handle violations, as well as factors operators must consider when preparing their SPCC plan(s). Each site requires a site-specific plan, including a detailed facility diagram, which must be reviewed and certified by a Professional Engineer. However, it is the owner/operator who is ultimately responsible for compliance, implementation, training of personnel, and subsequent inspections and updates.

Specific details of how to obtain a plan, along with examples of the types of data sheets used, were especially useful to many in the audience.

 

Candidate Selection for Horizontal Drilling with Case Studies in Osage and Tulsa Counties , Oklahoma (July 2005)

(Details of the related DOE pilot study are reported in SPE Papers 89373 and 94094.)

Horizontal wells have many applications and can be cost effective. However, the economic success rate for all horizontal wells - over 25,000 worldwide - is 2 out of 3. For use in secondary recovery operations, an understanding of both the reservoir and the field's geology is required. Modeling the reservoir and conducting a history match to validate that model and predict horizontal well performance are recommended to prevent financial disaster.

This workshop was a result of efforts made during a DOE-supported horizontal waterflood pilot project in the Bartlesville sands in northeastern Oklahoma . The lessons learned and the adjustments made to produce both an economic and a technical success were described in detail.

Directional permeability is a critical parameter. For primary recovery, the well should be drilled perpendicular to natural fractures, whereas for secondary recovery, it should be drilled parallel to the natural fractures. The effect of the following factors on the technical and financial aspects of a horizontal-well project were also addressed:

• Production history

• Remaining reserves

• Well cost - new vs. re-entry

• Completion technique - type of casing, whether or not to stimulate

• Wellbore stability (rock strength)

• Drilling method - overbalanced vs. underbalanced

• Direction and placement of wellbore

• Location of kick off point on vertical portion of wellbore

• Radius of curve - short (40-100') or medium (100-500'). The curve is the expensive portion of drilling a horizontal well. Of particular interest was the drilling assembly used to drill the curves. An actual model was available for inspection.

Case studies of the DOE program were summarized. This investigation showed that in old fields where conventional waterfloods were inefficient, production could be re-established with horizontal wells placed in areas of adequate oil saturation and where reservoirs have sufficient bottom hole pressure (~125 psi), as long as injection rates are kept below fracture parting pressure.

 

Morrow and Springer in the Southern Midcontinent (May 2005)

This two-day symposium was the eighteenth in an annual series focused on the search for and production of oil and gas resources in the southern midcontinent. The attendance of well over 200 persons is an indication of the high level of interest in the Morrow and Springer.

Morrow and Springer rocks underlie large portions of Oklahoma , primarily in the Anadarko, Ardmore and Arkoma Basin areas, with the Anadarko Basin strata extending north into southwestern Kansas and the Hugoton Embayment and west into the panhandle of Texas . The rock units have been prolific producers of hydrocarbons. Currently, their oil production is generally in decline; but gas production is holding steady, as the number of gas wells being drilled has increased.

The 21 talks and 4 poster presentations covered a wide range of information concerning the Morrow and Springer. Most dealt with sandstone reservoirs but there were 2 papers on carbonate deposits. Topics included:

•  field studies of secondary (Rice Field water flood) and tertiary (Postle Field CO2 flood) recovery methods in Morrow sands

•  hydraulic fracture growth in deep Springer reservoirs

•  production of iodine from brines in the Morrow

•  deployment of logging tools in complex or problem holes

•  BTU heat value and non-hydrocarbon content of Morrowan gases in Kansas

•  modeling with web-based freeware to find overlooked pay

•  use of improved 3D seismic imaging, i.e., frequency signals on the order of 160Hz, to achieve resolution of 20-ft sands

•  trapping mechanisms, using lessons learned from studying the Cromwell

Additional papers provided insights on aspects of integrating detailed facies studies with sequence stratigraphy to characterize the type and quality of a reservoir. The role and importance of particle grain size, coatings, cements, compaction and/or dissolution events in the development of porosity within reservoir rocks was discussed by other speakers.

The overall message of the meeting was one of optimism, that opportunities for exploration and development still exist in Morrow and Springer sediments. The key to success, even if one is simply going deeper or doing infill drilling, is to gain a better understanding of the immediate depositional environment by looking at all the data, integrating that data with modeling if possible, and relating results to performance history.

Principles of Polymer Gel for Water Reduction with Illustrative Field Applications (April 2005)

It has been estimated that the United States produces 7 barrels of water for every barrel of oil produced. One possible way to reduce this ratio involves polymer gel technology.

Two speakers, one instrumental in developing polymer gel technology and the other owner and operator of a company specializing in polymer gel treatments, gave this workshop. Both focused on the currently popular, organic polymer gel systems cross-linked with chromium III. More robust than their predecessors, these systems can withstand broader ranges of pH and temperature and higher levels of H 2 S, TDS and salinity. Success rates for application of this technology to water shutoff problems vary from ~60% to >90%, depending on operator involvement and the experience and teamwork of the technology and service providers.

The use of polymer gels for water shutoff problems is highly reservoir specific. Not all problems can or should be remedied with gels. Critical steps for achieving successful treatment are:

1. Correctly identify the excess water-production problem, including whether there is matrix or fracture permeability.

2. Determine if the problem is amenable to gel treatment.

3. Custom design an appropriate fluid treatment system, including the type and concentration of polymer and cross-linking agent to be used.

4. Properly design and size the treatment, considering distance, volume and rate variables.

5. Use an appropriate placement procedure, including making certain preparations before pumping and monitoring pressure gradients during treatment.

Criteria for selecting a good candidate well are: high WOR; excessive water production; significant remaining mobile hydrocarbons; high fluid levels in wellbore; and low oil recovery.

Numerous case history studies showing water reduction, incremental oil/gas recovery, and cost/bbl for a variety of reservoirs and/or fields in Oklahoma and elsewhere were presented. Two emerging trends briefly mentioned involve the addition of solids to polymer gels to increase their compressive strength and combining water shutoff treatments with stimulation.

Extended periods of open discussion followed both morning and afternoon sessions to handle the large number of questions and comments from attendees.

Deep Gas Well Stimulation Workshop (February 2005)

This well-attended workshop focused on results of a study done by Pinnacle Technologies as part of DOE's Deep Trek Program, which is an effort to develop economic drilling technology for deeper reserves. For purposes of this study, deep gas was defined as that occurring at >15,000 feet TVD (total vertical depth) or >350°F and >10,000 psi.

The presentation included a summary of current and projected deep gas well drilling activity in the United States; a discussion of factors dominating fracture growth in high temperature -high pressure environments; case histories from deep reservoirs in OK, TX, and WY; and empirical fracture modeling of several wells in each study area. Participating operators identified better high temperature frac fluids, staging with composite frac plugs to more efficiently stimulate multiple zones, and controlling proppant flowback as key recent advances in technology.

The case studies integrated fracture engineering and modeling with an analysis of production data, well tests, or fracture diagnostics to evaluate the overall effectiveness of each stimulation treatment.

Pinnacle encountered a problem in finding operators willing to participate in the study. Ironically, workshop participants, mostly engineers, commented on the need to involve more operators and acquire more operational details in order to make the case studies effectual.

An added feature of the program was representatives from three service companies who highlighted their respective company's progress on improving techniques and supplying the materials and equipment needed to withstand high pressures and temperatures. Some of the topics they discussed were safety and environmental issues, pinpoint stimulation, and maintenance of proppant pack permeability.

Difficult Completions - Methods of Recompleting Wells and Workovers (September 2004)

Results from both conventional and sidewall core analyses and various types of electric logs were used to discuss problems typically encountered in South Arkansas wells. The presentation of 8 case studies illustrated how one company handled 5 types of difficult completions:

  • tight (limestone) rock
  • producing zone dangerously close to water
  • psychological barrier - deciding whether to go after the most payback or the quickest payback
  • (not) learning from other people's mistakes
  • what to do when industry tools and lab tests give the "wrong" answer

A unique feature of this workshop was the widespread interaction of its participants, who offered their experience-based tips on practices and technologies that are applicable in South Arkansas.

Petroleum Geology of the Deepwater Jackfork Group and Atoka Formation (August 2004)

(Workshop presentation slides available as OGS Open File 46-2004. For an in-depth summary, go to http://www.pttc.org/solutions/sol_2004/539.htm.)

Deepwater sequence stratigraphy explains the nature of reservoir material deposited through a complete sea level cycle, from lowstand through transgressive to highstand systems tracts. Details of well log expressions of these systems tracts, combined with borehole image logs and cores, can be used in correlations and to help differentiate cemented Jackfork sheet sands (associated with fracture porosity) from friable Jackfork channel sands (associated with matrix porosity).

Detailed well log correlations of Atoka and adjacent strata delineate a comprehensive regional picture of the Arkoma Basin within a sequence stratigraphic framework. Atoka deposition resulted from two third-order sea level cycles. Twenty-nine stratigraphic cross sections based on conductivity, gamma ray and litho-density logs are developed from 159 wells. Shale packages with characteristic specific conductivity patterns are defined and tracked across the basin to establish boundaries; they show the Atoka thins significantly to the north and west. This sequence stratigraphic model can aid as a predictive tool for sandstone distribution throughout the Oklahoma portion of the Arkoma Basin.

The Status of Recent Coalbed-Methane Development in Arkansas and Oklahoma (July 2004)

A cutting-edge drilling technology found useful in unconventional coalbed reservoirs in the Arkoma Basin involves a dual well system: a horizontal/service wellbore and a nearby vertical/producing wellbore. Adding numerous side laterals results in a pinnate (leaf) pattern. Major advantages include minimal surface disturbance, drainage of large area, quicker/higher gas recoveries, uniform drainage and pressure depletion, and less produced water.

In the Desha Basin Project, a multi-state government-funded consortium, plans are to core five deep test wells in the southeastern Arkansas lignite resource area to determine whether some of the deeper deposits may be in the producible gas range as preliminary USGS studies indicate.

articles