Cyclic steam injection has been used in California since the 1960s. It has been used as a commercial technique to recover oil from diatomite since the mid-1990's. This paper is a synopsis of the analysis and interpretation of over three years of steam injection flow rate, pressure and temperature data from Santa Maria Energy's (SME) cyclic steam injection pilot project in the diatomite zone in the Sisquoc formation on the Careaga Lease in the Orcutt Oil Field, Santa Barbara County, California. The pilot consists of 19 cyclic steam injection wells configured in a 4x5 matrix spaced about 120 feet apart producing from a depth of about 925 feet. Operating practices are used specific to Careaga Lease geologic and reservoir features that include a tailored range of steam injection rates and steam volumes for each steam injection cycle. Comprehensive surveillance and steam injection management protocols are in place for maintaining a safe and reliable operation. The discussion that follows examines data gathered automatically at each well and their real time analyses. Cycle-by-cycle analyses of steam injection and soak periods for all SME wells show (a) no indication of fractures being induced and (b) that large skin effects are present during steam injection in this project. The latter calls into question use of the tubing wellhead pressure as an indicator of the reservoir pressure while injecting steam. Based on the analysis and interpretation of the data, it appears that mechanisms, such as differential thermal expansion of the heated rock and its fluids, are likely to be occurring within the geologic setting of this project to an extent not seen in more permeable rocks and could be favorably affecting the overall production response. Other possible effects are also cited.

Summary. An infill well program involving 574 wells in previously steamflooded idle reservoirs proved to be economical and increased recovery in some areas from 50 to 58%. These wells were recompleted to zones under active steam drive and showed similar recovery increases in addition to acceleration of reserves. These increases in recovery were attained without additional fuel. Introduction The Kern River field is a large, shallow, heavy-oil deposit located 5 miles [8 km] northeast of Bakersfield, CA. The productive formation is a sequence of sands called the productive formation is a sequence of sands called the Kern River series. The structure is a simple homocline, dipping southwest at 5 deg. [0.09 rad]. The updip sands pinch out, and downdip is bounded by an oil/water contact. These fine-to-very-coarse sands, averaging 60 ft [18.3 m] in thickness, are separated by silt and clay interbeds. The unconsolidated sands have high permeabilities of 1 to 5 darcies and porosities of 28 to 33 %. The average oil viscosity and reservoir temperature are 4,000 cp and 85 deg. F [4 Pa.s and 29 deg. C], although viscosities vary between sands from 2,000 to 40,000 cp [2 to 40 Pa.s]. Texaco Inc.'s Kern River field steamflood involved more than 3,640 producing wells and 1,875 injection wells before infill drilling. The field had been developed on 2 1/2-acre [10 100-m2] five-spot patterns. Up to seven sands are swept, one at a time, usually beginning in the lowest sand. These sands range in depth from 300 ft [91.4 m] in the northeast section of the field to 1,200 ft [366 m] in the southwest. The reported Kern River steamflood oil recovery ranges from 42 to 73% of presteam oil in place (OIP), with an average of 50% a generally place (OIP), with an average of 50% a generally accepted recovery efficiency. We have completed steamfloods in 1,500 pattern sands. Some of the techniques for improving steamflood recovery were summarized by Bursell. They include infill wells, partial or limited perforation of producers, variable steam quality and rate, injection diverting, crossflooding, and injector-to-producer conversion. Before infill wells were drilled, numerical simulation work indicated several attractive benefits from infill wells:recovery increases from 50 to 60% of OIP even with well spacing as small as 0.625 acre [2530 m2],possible similar recovery increase from the 1,500 completed and idle pattern sands, andaccelerated recovery and fuel pattern sands, andaccelerated recovery and fuel reduction. These results have been proved. The following review of four projects will compare theoretical to actual results. The 574-infill-well program was unusual in that most of the wells were first completed in idle sands and were subsequently perforated in upper active steamfloods and the well spacing was reduced to only 0.625 acre [2530 m2] per well. The patterns went from 1.25- to 0.625-acre [5060- to 25 30-m2] well spacing by conversion of a 2 1/2 -acre [10 100-m2] five-spot into a 2 1/2-acre [10 100-m2] nine-spot pattern. 1970 Canfield Project The 1970 Canfield project covers 148 acres [599×103 m2] in the updip portion of the Kern River field, as shown in Fig. 1. A cross section through the project (Fig. 2) shows the steamflood intervals. Table 1 shows reservoir properties. Steam injection in the first displacement sand, Sand R1, began in July 1970. Injection was ended at the steamflood economic limit in Sept. 1977. Fig. 3 shows project performance history. Cumulative steamflood oil recovery performance history. Cumulative steamflood oil recovery from the project was 147,000 STB [23 400 stock-tank m3] per pattern, or 57% of the predisplacement OIP, as shown in Table 2. In Feb, 1978, the project was recompleted upward to Sand R. Conduction heating from the Sand R1 displacement raised Sand R temperature from 85 to 165 and 92 deg. F [29 to 74 and 33 deg. C] at the base and top of Sand R, respectively (Fig. 4). Previous work 4 reported the beneficial effects of this preheating. Steam injection in Sand R was terminated in the 55 patterns during the period from Oct. 1982 to June 1984. Again, injection was ended in these patterns at the steamflood economic limit. Steamflood oil recovery was 97,200 STB [15 450 stock-tank m3] per pattern, or 49%, as shown in Table 2. During this same 1982–84 period, recompletion and injection into Sand K (above Sand R) was started. Concurrently, 80 infill wells were drilled and initially completed in the idle Sand R1. As shown in Fig. 5, these wells were drilled at midpoints of the pattern boundaries. The average production rates for these infill wells are shown in Fig. 6. SPERE P. 243

Cyclic steam stimulation (CSS) has been used in California since the 1960s. It has been used as an effective method for commercial oil recovery from the very low permeability diatomite formation since about the mid-1990's. Santa Maria Energy (SME) operates a CSS project in the Opal A diatomite of the Sisquoc formation on the Careaga Lease in the Orcutt Oil Field in Santa Barbara County, California. A 19-well CSS pilot has been operational since October, 2009. SME has received entitlement to proceed with an expansion consisting of 110 additional new wells. The CSS process designed by SME for the diatomite zone is one that works without fracturing the reservoir rock. An earlier paper was presented that describes techniques used for monitoring steam injection to help keep the injected steam confined to the zone of interest1. One such technique is Hall's method2 for water injection and adopted for steam. Corresponding algorithms have been programmed into a supervisory control and data acquisition (SCADA) system to survey and analyze all steam injection cycles for all wells. The method has also been used to analyze steam injection step rate tests (SRT). This paper discusses: Two SRT's performed using steam injection; The analytical techniques used; and The results. Of special importance is that matrix flow is seen for CSS even though the injection bottom-hole pressure exceeds that which might normally be considered the rock fracture or parting pressure. This is due to partial plugging and other phenomena during steam injection that occurs to an extent not realized in more permeable rocks (such as very high permeability sandstones). These effects produce extra pressure drop during steam injection into the diatomite zone. This raises questions about the misuse of tubing wellhead pressure readings during steam injection as a reliable indicator of the reservoir formation parting pressure. As a result of this and other work, SME has adopted a specific range of CSS injection rates that are below a critical rate to help insure steam injection is confined to the zone of interest.

Cyclic steam stimulation (CSS) in the California Opal A diatomite has been a successful commercial oil recovery technique since the 1990s. This paper analyzes the production performance of several California CSS diatomite projects comparing actual and calculated steam-oil ratios, SOR, as a function of oil recovery to ascertain whether a project is performing up to its full potential. SORs are computed using simplified Buckley-Leverett fractional flow theory applied to steam injection. SOR, or its reciprocal oil-steam ratio (OSR), have always been useful qualitative indicators of CSS project performance; but have not been used to optimize production performance other than to say operators should strive to keep the SOR low, or the OSR high. We show that an SOR equal to about 1 is what a CSS diatomite project should achieve through the recovery of about 20% of the oil-in-place, or more, to yield the highest oil production for a given set of conditions. A corresponding “optimum” steam injection rate is discussed. Projects that are managed this way have the highest average oil production rate per well and the lowest instantaneous SOR. This study shows that steam over-injection in the diatomite is common even when the injected cold water equivalent (CWE) steam is “in balance” with the oil and water that are produced. Although not discussed in detail, we postulate that the low permeability diatomite has an inherent low rate of heat absorption compared to other oil bearing rocks that can cause too much vapor to accumulate around the well when steam injection becomes excessive. Relative permeability effects develop during flow back that give way to (a) the preferential flow of steam to the producer and (b) constrained re-saturation of the heated zone. Avoiding this tendency helps insure good project performance including high oil flow rates and high oil recovery. Although the calculation method we discuss is used for CSS in the low permeability diatomite, it should be helpful in all CSS applications. Improving CSS steam practices will have the added benefit of lowering the carbon intensity of the oil that is produced. Our analysis uses published data for the needed input parameters including information from the California Division of Oil, Gas and Geothermal Resources (DOGGR) internet web data base.

This paper discusses a pilot project for exploiting the shallow oil-saturated diatomite located on the Careaga Lease in the Orcutt Oil Field, Santa Barbara County, California. The project is one of two successful new operations underway in the Central Coast of California that show oil production by cyclic steam stimulation of oil-saturated diatomite is possible. This method of oil production has been a success in the San Joaquin Valley since around 1996. It is now extended to a similar accumulation located over 100 miles away. This case study chronicles the encouraging production response from a similar virtually unexploited zone known for over 100 years. Under full development, expected production could exceed historical peak levels from a resource many considered too shallow and too tight to exploit. Modern techniques are considered vital to making the Orcutt diatomite productive and successful. The Orcutt oil field is located south of the town of Santa Maria, in Santa Barbara County, California. Discovered in 1901, it was first called the "Santa Maria Field" until the larger Santa Maria Valley oil field was discovered in the mid- 1930's. The name was changed to the Orcutt oil field. Cumulative oil production is in excess of 181 million barrels. Daily oil production is at a 25-year high. It is the largest onshore producing field in Santa Barbara County.