Appendix 2
Well Blowout Coding
Blowouts have been coded for (among other aspects) whether the surface blowout occurred from the well (or well head) or from the ground surface away from the well. The presumption was that the fluid exited from the well—unless the record specifically noted that the fluid exited from the ground surface away from the well. The blowouts were also coded for the type of well involved.
The well-type coding could not be narrowed down to a single well type for two of the coded blowouts. These occurred during drilling and plugging and abandoning, and therefore the well type was not of consequence for this report. Single codes were assigned with confidence to all the remaining coding fields in the 48 records.
Well Construction Blowout Rate Bases
DOGGR (1992 to 2006) lists well construction activities and well totals by various categories. The reports list the number of borings drilled and wells plugged and abandoned (P & A) each year. The total number of borings drilled and P & A during the study time period was used directly as the basis for calculating the blowout rates during these activities.
The number of rework completions is not tracked by DOGGR, but the number of rework permits issued is a close proxy for this activity (M. Stettner, personal communication). DOGGR (1992 to 2006) lists the number of permits issued for drilling, reworking, and P & A. Wells drilled, and P & A from 1991 to 2005, totaled 97% and 90% of the permits issued for each activity from 1990 to 2004, respectively. On this basis, it was assumed that rework occurred on 95% of the wells for which permits were issued.
The number of construction operations in thermally enhanced production areas was estimated by multiplying the total number of operations by the fraction of all production and injection wells with steam influence. The estimation of this fraction is discussed below.
Thermal Versus Nonthermal Blowout Per Well Rate Basis
The number of production wells influenced by thermally enhanced recovery operations is not readily available from DOGGR. Therefore, DOGGR personnel suggested estimating the number of thermally enhanced production wells by multiplying the fraction of total oil production resulting from thermally enhanced incremental oil production (available from DOGGR) by the total number of wells (Mike Stettner, personal communication).
The number of production wells listed in DOGGR’s annual reports includes the cyclic-steam wells (M. Stettner and D. Tuttle, personal communication). The annual reports also list steam injected (on a liquid equivalent basis) in cyclic and flood operations separately. Thus the approach suggested by DOGGR was modified to more accurately estimate the total number of thermally enhanced production wells, as shown below.
(A2-1)
(A2-2)
where is the steam-oil ratio, is the injected steam volume in liquid equivalent, is the produced oil, the subscript is for cyclic steam, and the subscript is for steam flood. Equations (1) and (2) can be solved for and and combined to yield
(A2-3).
Now
(A2-4),
so the fraction of the total thermal-incremental production which is caused by cyclic steam is given by
(A2-4).
Solving for
(A2-6).
Substituting Equation 3 into Equation 6 and assuming ( gives
(A2-7).
was calculated for District 4 for each year in the study period using Equation 7 and was calculated using Equation (4).
During the study period, 22% of the steam was injected cyclically and 78% was injected as a flood. Based on the analysis approach presented here, it is estimated that:
- Of the total thermal oil increment, 16% was recovered using cyclic steam and 84% was recovered through steam flooding during the study period.
- The average steam-oil ratio for cyclic-steam injection was 5.3; for steam flooding, it was 3.5. These values are near the center of the ranges given for and by Schlumberger ( indicating the estimation approach is reasonable for deconvolving the total thermal oil increment into portions due to cyclic steam and steam flooding.
The number of production wells involved in steam flooding was calculated by subtracting the number of cyclic-steam wells from the production well total and multiplying by the steam-flooding oil production divided by the total non-cyclic steam oil production. The result was checked by examining the resulting ratio of steam-flood production to injection wells. The average ratio during the study period is 3.4. This is in the range for a field covered by a nine-spot, injector-centered well pattern. This is in fact the pattern in Cymric field located northwest of the town of McKittrick in the western portion of District 4(A. Urdaneta, personal communication), which has the fourth largest number of steam-flood injectors (245). A square area covered by 245 injectors in a nine-spot pattern would have a ratio of 3.5 production wells per injector, which matches the ratio of 3.4 resulting from the estimation process well.
The number of active water disposal wells in thermally enhanced recovery areas was estimated by multiplying the total number of water disposal wells by the fraction of total oil production resulting from thermal recovery. The remaining wells were presumed to be in nonthermal areas. The active well total for nonthermal fields also included all gas production and injection (pressure maintenance), water flood injection, and air injection wells. A review of field operation data from DOGGR indicates that gas production and injection and water and air flooding occurred primarily in nonthermal fields or pools.
All blowouts from the ground surface away from a well head occurred in association with steam-injection wells. Consequently, the basis for the rate of ground surface blowouts in fields with thermally enhanced recovery is the total number of steam-injection wells.
The number of P & A wells in thermally enhanced production areas was estimated by multiplying the total number of P & A wells by the estimated fraction of all wells influenced by steam. The total number of P & A wells as of the beginning of the study period was 30,383 (D. Tuttle, personal communication). This total was updated for each year in the study period by adding the yearly number of P & A operations according to the DOGGR annual reports.
Blowouts Per-Fluid Volume Rate Basis
Four fluids are produced and/or injected in District 4: oil, gas, steam and liquid water. The total blowout rates for well servicing, wells in operation, and other events are based on the sum of the volumes of these four fluids. The assignment of these fluids to nonthermal or thermal production, and to steam flooding versus cyclic steam, is described in order below.
Thermal incremental oil production is reported by DOGGR. Nonthermal oil production was given by subtracting the thermal increment from the total production. The thermal increment was deconvolved into increments resulting from the steam flooding and cyclic steam using Equation (7) in this appendix as described above.
As indicated in the report, all gas production and injection was included in the nonthermal fluid volumes based upon DOGGR (1992 to 2006). Besides listing almost all gas production and injection in nonthermal fields, DOGGR (1992 to 2006) also reports the gas-oil ratio in nonthermal fields producing gas is typically in the hundreds to thousands, while the ratio in thermal fields is in the tens to hundreds. As a consequence, the gas in nonthermal fields likely occurs as a separate phase, while the gas in thermal fields is likely dissolved in oil.
Natural gas produced and injected is reported in standard cubic feet. This was converted to actual volumes transferred through the wells to provide a basis for the blowout rate per fluid volume. Most dry gas production occurred in the Elk Hills field. DOGGR (1998) reports a gas gravity of 0.65-0.70 (air = 1.0) for this field. The gas gravity was taken as 0.7 for conversion purposes. DOGGR (1998) reports the approximate temperature in the three most productive dry gas pools was about 40°C (104°F). DOGGR (2007) provided tubing pressure data for only one of these pools, located in the Bowerbank field. These figures suggest that a well-head pressure of three megapascals (440 psi) is appropriate. Using these values, Standing and Katz (1942) provides a gas density of 26 kilograms/m3 (1.6 lbs/ft3). DOGGR (1992 to 2006) indicates little water production in dry gas fields, so the fluid basis for dry gas well blowouts consists only of the reported gas production.
The steam volume is in steam/water equivalent converted from the liquid equivalent reported by DOGGR (1992 to 2006) using the assumptions detailed in this report. DOGGR (1992 to 2006) reports total produced water and injected during disposal and flooding. DOGGR (1992 to 2006) indicates water flooding occurs almost exclusively in nonthermal fields or pools, so all this fluid is included in the nonthermal fluid total. Water production and disposal associated with thermal oil recovery is not reported, and so was estimated. The ratio of water production to steam injection appears to partially correlate with the ratio of cyclic steam to total steam injection as shown on Figure A-1. This figure indicates slightly more water is injected than produced during cyclic steaming, while more than twice the water is produced as injected during steam flooding.
Figure A-1. Relationship between excess water production and type of steam injection. The symbol size represents total water production.
Cyclic steam injection was 22% of all steam injection in the six pools with the largest steam injection volumes. At this ratio, 69% more water was produced than injected. Since the district-wide cyclic to total steam-injection ratio was also 22%, thermal water production was taken as 169% and water disposal was taken as 69% of the steam-injection liquid equivalent. This results in an 86% water cut in the thermal fields and an 83% cut in the nonthermal fields, which is reasonable. The remaining water production and disposal was assigned to nonthermal fields.
Subsurface Steam Area Estimation – Single Pool Per Field Assumption
The area in District 4 with steam in the subsurface was estimated from the field area and the number of cyclic steam, steam flood, and total production wells reported for each field by DOGGR (1992 to 2006). The number of production wells with steam influence was taken as the cyclic-steam wells, plus the number of production wells influenced by steam flooding. This was computed as the number of steam-flood wells multiplied by the steam-flood-production-to-injection-well ratio estimated and discussed above.
On a yearly basis, the number of production wells with steam influence was divided by the total number of production wells, to give the fraction of production wells with steam. If this fraction were greater than one, then it was set to one. This occurred for the Kern River field in most of the study years, and in the Cymric field for a few of the study years. The highest raw fraction was 1.5, for the Kern River field in 1996.
The fraction of production wells with steam was then multiplied by the area of each field, to give the area with steam in each field each year. These values were averaged over the ten years of study and summed to give the total area with steam in the subsurface in the district. The area using a maximum fraction of one for production wells with steam was only 4% less than the area without setting this maximum, indicating the stability of the estimation technique.
REFERENCE
StandingMB, Katz DL (1942)Density of natural gases. Trans AIME 146:141-149
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