94-8304. Railroad Commission of Texas, Tight Formation Determination Texas 156, Spraberry (Trend Area) Formation, FERC No. JD94-02876T; Preliminary Finding  

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    From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
    [FR Doc No: 94-8304]
    
    
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    [Federal Register: April 7, 1994]
    
    
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    DEPARTMENT OF ENERGY
    [Docket No. GP94-5-000]
    
     
    
    Railroad Commission of Texas, Tight Formation Determination--
    Texas 156, Spraberry (Trend Area) Formation, FERC No. JD94-02876T; 
    Preliminary Finding
    
    Issued April 1, 1994.
    
        The Railroad Commission of Texas (Texas) determined that the 
    Spraberry (Trend Area) Formation (Spraberry Formation), underlying the 
    Preston and Shackelford Units in portions of Midland County, Texas, 
    qualifies as a tight formation under section 107(c)(5) of the Natural 
    Gas Policy Act of 1978.
        For the reasons discussed below, the Commission issues this Notice 
    of Preliminary Finding that the determination is not supported by 
    substantial evidence.
    
    Background
    
    1. Texas' Determination
    
        On February 15, 1994, the Commission received Texas' notice 
    determining that the Spraberry Formation underlying the Preston and 
    Shackelford Units in Midland County, Texas, qualifies as a tight 
    formation. Parker & Parsley Development Company (Parker & Parsley) is 
    the applicant before Texas. The recommended area is approximately 
    52,000 acres in size.
        The record shows that the Spraberry Formation consists of three 
    distinct productive intervals--the Upper Spraberry, Lower Spraberry, 
    and Dean formations--and that these reservoirs have been producing oil 
    and/or gas for more than 40 years. The record further shows that there 
    are approximately 182 currently active wells in the Spraberry Formation 
    within the recommended area and that at least 100 additional wells have 
    been produced to abandonment. The record also indicates that natural 
    fractures enhance the permeability of the formation.
        Texas concluded that the Spraberry Formation meets the Commission's 
    permeability guideline based on:
        (1) Pre-stimulation pressure buildup test data from one well 
    drilled in the recommended area, the Preston Unit Well No. 3414-A 
    (#3414-A well);
        (2) Type curve data from 22 stimulated Spraberry wells, 17 of which 
    are located outside of the recommended area;
        (3) Core tests from three wells within the recommended area; and
        (4) A table from the ``Atlas of Major Texas Oil Reservoirs'' (1983) 
    showing that the average permeability to oil in the Spraberry (Trend 
    Area) formation is zero.
        Texas' finding that the formation meets the Commission's oil and 
    gas flow rate guidelines is based on pre-stimulation flow test rates 
    from the #3414-A well, which was drilled late in 1992.
    
    2. Regulations/Commission Precedents
    
        To qualify a formation as a tight formation, 
    Sec. 271.703(c)(2)(i)(A) of the Commission's regulations requires the 
    jurisdictional agency to determine that the expected in situ (matrix 
    and natural fracture) gas permeability throughout the pay section is 
    0.1 millidarcy (md) or less.1 Sec. 271.703(c)(2)(i)(B) of the 
    regulations requires the jurisdictional agency to show that the 
    expected pre-stimulation stabilized natural gas flow rate, against 
    atmospheric pressure, for wells completed for production in the 
    formation is not expected to exceed the applicable maximum flow rate 
    specified in the table in that section (290 Mcf per day in this 
    case).2 Finally, Sec. 271.703(c)(2)(i)(C) of the regulations 
    requires the jurisdictional agency to show that wells completed for 
    production in the formation are not expected to produce more than five 
    barrels of crude oil per day, prior to stimulation.3 According to 
    Texas, the Spraberry Formation meets these guidelines.
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        \1\18 CFR 271.703(c)(2)(i)(A) (1993).
        \2\18 CFR 271.703(c)(2)(i)(B) (1993).
        \3\18 CFR 271.703(c)(2)(i)(C) (1993).
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        However, in Order No. 99, the Commission defined a tight formation 
    as ``a sedimentary layer of rock cemented together in a manner that 
    greatly hinders the flow of gas through the rock.''4 The 
    Commission held in a prior preliminary finding that:
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        \4\Order No. 99, FERC Statutes & Regulations, Regulations 
    Preambles (1977-1981) 30,183 at 31,261.
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        The Commission established guidelines on permeability and flow 
    rates to be used to evaluate the physical characteristics of the rock 
    in the formation in order to show that the formation is tight, which 
    should have been the case prior to the onset of sustained production 
    from the formation. (emphasis added) Accordingly, the Commission 
    further clarified [in Order No. 99] that the objective of the rule was 
    to ``provide incentives to develop tight formations, not to provide 
    incentives to develop all formations with low pre-stimulation 
    production rates.''5 As a result, the Commission did not intend to 
    permit a formation that does not actually meet the definition of a 
    ``tight formation'' to qualify based on currently low permeability and 
    flow rate values that are merely a side effect of prior conventional 
    levels of production.''6
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        \5\FERC Statutes & Regulations, Regulations Preambles (1977-
    1981) 30,183 at 31,276. See also Interim Rule, FERC Statutes & 
    Regulations, Regulations Preambles (1977-1981) 30,130 at 30,906.
        \6\Railroad Commission of Texas, 63 FERC 61,067 (1993). A final 
    order affirming the tight formation determination was issued by the 
    Commission (64 FERC 61,225) after the applicant supplemented the 
    record with data showing that original reservoir conditions also met 
    the Commission's guidelines.
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        Similarly, the Commission held in another preliminary finding that 
    the formation did not qualify as a tight formation because current-day 
    qualifying values were the result of water influx due to sustained 
    production, not the result of the way the rock was cemented 
    together.7
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        \7\Mississippi Oil and Gas Board, 57 FERC 61,129 (1991). The 
    Commission did not issue a final order because the applicant 
    withdrew the application.
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    Discussion
    
        Based on a review of the current record, the records in another 
    proceeding involving the Spraberry Formation,8 and a study by the 
    Texas Bureau of Economic Geology addressing the Spraberry Formation 
    underlying the recommended area,9 the Commission believes that the 
    determination is not supported by substantial evidence, as explained 
    below.
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        \8\See 64 FERC 61,004 (1993) where the Commission preliminarily 
    found that the Spraberry Formation in the Midkiff Unit did not meet 
    the tight formation guidelines because the record did not:
        (1) Reflect natural fracture permeability;
        (2) Contain gas flow rate data that was representative of 
    initial conditions in the reservoir; and
        (3) Contain substantial evidence that the formation met the oil 
    flow rate guideline. The Commission did not issue a final order 
    because the applicant withdrew its application. The acreage covered 
    by the current recommendation is contiguous to the Midkiff Unit.
        \9\``Heterogeneous Deep-Sea Fan Reservoirs, Shackelford and 
    Preston Waterflood Units, Spraberry Trend, West Texas,'' 1988, Texas 
    Bureau of Economic Geology.
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        Commission review shows that the record does not reflect initial 
    conditions (i.e., before sustained production, pressure decline, and 
    filling of rock pore spaces with water) because virtually all of the 
    data wells were completed in the Spraberry Formation from 1980 to 1993, 
    long after production from the formation commenced.10 In addition, 
    the record does not contain substantial evidence supporting the use of 
    oil production type curve analysis as a method to calculate effective 
    gas permeability. First, all 22 type curve wells were analyzed with 
    equations where current gas-oil rations were used, as well as a single 
    current reservoir pressure of 1,000 psia and the corresponding fluid 
    properties at that pressure.11 Second, the oil permeabilities used 
    in the calculations were derived by the analysis of the 22 wells' 
    historical oil production. It is unclear how the oil permeabilities 
    thus calculated can apply to the calculation of gas permeability prior 
    to sustained production.
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        \1\0The one exception is a 1966 core permeability data well.
        \1\1The Commission also notes that the record does not show how 
    current pressures in wells first produced from 1980 to 1988 would be 
    the same.
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        Moreover, the Commission believes that the record does not show 
    initial conditions since waterflooding projects initiated in 1964 have 
    affected most of the recommended area. Specifically, Commission records 
    show that the Upper Spraberry formation in the Preston and Shackelford 
    Units, the most productive interval of the three productive intervals, 
    has undergone unitized waterflooding since 1964.12 These records 
    also show that by 1980, the waterflood front had expanded over most of 
    the Preston and Shackelford Units and as a result, most wells were 
    producing more than 75% water.13
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        \1\2The records show that unitized waterflooding also began in 
    the Lower Spraberry in 1964, but was discontinued in 1968 when it 
    was determined that 80% of producing capacity was attributable to 
    the Upper Spraberry and that water injection did not cause 
    additional oil to be produced from the Lower Spraberry. None of the 
    records reviewed shows any waterflooding operations in the Dean 
    formation.
        \1\3The Commission's records do not show whether the Lower 
    Spraberry interval also produces 75% water. However, the record 
    contains no evidence showing that hydraulically fractured Lower 
    Spraberry wells would not be in communication with the Upper 
    Spraberry interval as a result of the extensive system of 
    interconnected natural fractures throughout the Spraberry Formation, 
    thereby allowing water encroachment.
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        Our review also shows that at original conditions, the Spraberry 
    Formation was a crude oil reservoir with a solution gas drive. Such 
    reservoirs initially have zero effective gas permeability by virtue of 
    the fact that all the gas is dissolved in oil until reservoir pressure 
    declines sufficiently, through sustained production, to allow free gas 
    to form (known as the ``bubble point''). Thus, it appears that gas 
    could not flow at initial conditions because the pores of the rock were 
    filled only with oil and water, not because of the way the rock was 
    cemented together.
        Finally, we conclude that one oil and gas flow rate data well 
    (#3414-A), regardless of its completion date, does not constitute 
    substantial evidence showing that the Spraberry Formation meets the 
    flow rate guidelines in the recommended area because of the geological 
    characteristics of the Spraberry Formation in the recommended area. 
    Commission records show that Spraberry sediments in this area were 
    deposited along two depositional axes running roughly north-south. The 
    records further show that, at initial conditions, wells located along 
    the eastern axis produced two to six times as much oil as wells located 
    between the two axes, and that wells located along the western axis are 
    characterized by high water production. The records also show that 
    Spraberry reservoirs in the recommended area are highly 
    compartmentalized due to extensive natural fracturing and complex 
    depositional boundaries. Accordingly, we conclude that data from the 
    #3414-A well does not provide sufficient evidence to support Texas' 
    determination that the formation meets the oil and gas flow rate 
    guidelines.
        Our review also shows that the record does not reflect the natural 
    fracture permeability in the formation.14 The Commission's records 
    clearly show that the original permeability of the formation (before 
    sustained production and water injection) substantially exceeded 0.1 md 
    due to the existence of interconnected, well-developed natural 
    fractures that extend throughout the Spraberry Formation within the 
    recommended area. The Commission's records also show that wells located 
    parallel to the northeast trend of the fractures have substantially 
    better reservoir permeability and flow rates than those located 
    perpendicular to the trend. Therefore, wells draining sands that do not 
    intersect the fracture system would be expected to reflect matrix 
    permeability only, the pressure regime of a closed system, and low flow 
    rates.
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        \1\4The Interim Rule issued February 20, 1980, in Docket No. 
    RM79-76, states that matrix permeability alone ``will not be 
    sufficient to qualify a formation, because formations with very low 
    matrix permeabilities may be economic to develop if fractures have 
    developed naturally. Therefore, to fulfill the guideline containing 
    the specific permeability limit, the formation's average effective 
    or in situ permeability throughout the pay section must be expected 
    to be 0.1 millidarcy, or less.'' FERC Statutes & Regulations, 
    Regulations Preambles (1977-1981) 30,130 at 30,906-07.
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        When a well has been cored, natural fracture permeability can only 
    be analyzed if the core has intersected a fracture, and the well 
    operator requests that vertical permeability be measured. Of the three 
    core analyses in the record, only one (the Shackelford No. 138-A well) 
    shows both horizontal (matrix) and vertical (fracture) permeability 
    values. However, only the horizontal permeability was used by the 
    applicant. Although the reported vertical permeabilities in the well 
    are lower than the horizontal permeabilities in the majority of the 
    core, the vertical permeability is listed as 55.27 md from one zone and 
    as ``TBFA'' (too broken for analysis) in another zone. In addition, the 
    record contains no evidence showing that the cored intervals in the 
    three wells are pay zones that were completed for production.
        Finally, the record includes one data well (#3414-A) where pressure 
    buildup calculations found that each of the three producing intervals' 
    permeability was less than 0.1 md. We acknowledge that pressure buildup 
    test analyses usually reflect total (i.e., matrix and fracture) 
    permeability found in a well's drainage area, and that, despite its 
    1992 drilling date, initial reservoir pressures in the #3414-A well 
    appear to be as high as those found in the Spraberry Formation at 
    original conditions. However, the record also shows that the Upper and 
    Lower Spraberry intervals produced high volumes of water during the 
    tests, and the record contains no evidence that any of the tested 
    intervals was actually completed for production. Therefore, we conclude 
    that the #3414-A well's high initial pressures and low permeability 
    values may be the result of its location in an area of lower reservoir 
    quality, and that the well's permeability does not reflect the 
    formation's original permeability throughout the recommended area.
        In light of the above, the Commission is issuing this preliminary 
    finding since the record:
        (1) Contains only gas permeability and hydrocarbon flow rate data 
    that do not represent initial conditions found in the reservoir prior 
    to sustained production, pressure decline, and water injection; and
        (2) Does not reflect natural fracture permeability.
        Under Sec. 275.202 (a) of the regulations, the Commission may make 
    a preliminary finding, before any determination becomes final, that the 
    determination is not supported by substantial evidence in the record. 
    Based on the foregoing facts, the Commission hereby makes a preliminary 
    finding that Texas' determination is not supported by substantial 
    evidence in the record upon which it was made. Texas or the applicant 
    may, within 30 days from the date of this preliminary finding, submit 
    written comments and request an informal conference with the Commission 
    pursuant to Sec. 275.202 (f) of the regulations. A final Commission 
    order will be issued within 120 days after the issuance of this 
    preliminary finding.
    
        By direction of the Commission.
    Linwood A. Watson, Jr.,
    Acting Secretary.
    [FR Doc. 94-8304 Filed 4-6-94; 8:45 am]
    BILLING CODE 6717-01-P
    
    
    

Document Information

Published:
04/07/1994
Department:
Energy Department
Entry Type:
Uncategorized Document
Document Number:
94-8304
Pages:
0-0 (1 pages)
Docket Numbers:
Federal Register: April 7, 1994, Docket No. GP94-5-000