Analysis of Pressure Communication between the Austin Chalk and Eagle Ford Reservoirs during a Zipper Fracturing Operation
The recent interest in redeveloping the depleted Austin Chalk legacy field in Bryan (TX, USA) mandates that reservoir damage and subsurface trespassing between adjacent reservoirs be mitigated during hydraulic fracture treatments. Limiting unintended pressure communication across reservoir boundaries during hydraulic fracturing is important for operational efficiency.
Sriniketh Sukumar, Ruud Weijermars *, Ibere Alves and Sam Noynaert
Harold Vance Department of Petroleum Engineering, Texas A&M University, College Station, TX 77843, USA;
Received: 11 February 2019 / Accepted: 29 March 2019 / Published: 18 April 2019
Our study presents field data collected in fall 2017 that measured the annular pressure changes that occurred in Austin Chalk wells during the zipper fracturing treatment of two new wells in the underlying Eagle Ford Formation.
The data thereby obtained, along with associated Eagle Ford stimulation reports, was analyzed to establish the degree of pressure communication between the two reservoirs. A conceptual model for pressure communication is developed based on the pressure response pattern, duration, and intensity. Additionally, pressure depletion in the Austin Chalk reservoir is modeled based on historic production data. Pressure increases observed in the Austin Chalk wells were about 6% of the Eagle Ford injection pressures.
The pressure communication during the fracture treatment was followed by a rapid decline of the pressure elevation in the Austin Chalk wells to pre-fracture reservoir pressure, once the Eagle Ford fracture operation ended. Significant production uplifts occurred in several offset Austin Chalk wells, coeval with the observed temporal pressure increase. Our study confirms that after the rapid pressure decline following the short-term pressure increase in the Austin Chalk, no residual pressure communication remained between the Austin Chalk and Eagle Ford reservoirs.
Limiting pressure communication between adjacent reservoirs during hydraulic fracturing is important in order to minimize the loss of costly fracturing fluid and to avoid undue damage to the reservoir and nearby wells via unintended proppant pollution. We provide field data and a model that quantifies the degree of pressure communication between adjacent reservoirs (Austin Chalk and Eagle Ford) for the first time.
Understanding the pressure state in the Austin Chalk and Eagle Ford shale reservoirs and their possible communication is important for petroleum engineering operations in several technical and proprietary ways. First, the pressure depletion history in each of the reservoirs controls the production rate of its wells. Since the Austin Chalk has been producing several decades prior to the development of the Eagle Ford Formation, knowing the state of their respective pressure depletion remains important for production forecasting and future field development planning.
Second, limiting pressure communication between adjacent reservoirs during hydraulic fracturing is important in order to minimize the loss of costly frack fluid and to avoid undue damage to pumps of nearby wells via unintended proppant pollution, a problem commonly faced by operators (reported by the managing director of E2 Operating, via personal communications with the authors on 29 October 2017). During a hydraulic fracture treatment proppant pollution is the invasion of proppants into the stimulated rock volume of an offset well. The fracture treatment can also affect the downhole equipment of offset wells.
The main focus of this study is on the analysis of pressure response data of shut-in Austin Chalk wells during Diagnostic Fracture Injection Tests (DFIT) and subsequent zipper fracking of the two nearby Eagle Ford wells. Our study was conducted on a lease space beneath the RELLIS campus, a research facility that is administered by the Texas A&M University System in Brazos County (TX, USA). A physical image and schematic map of the RELLIS campus are displayed in Figure 1a,b. The aerial view of the RELLIS Campus (Figure 1a) highlights the relevant oil well site locations in relation to the schematic map (Figure 1b). The images show that the individual wells considered are noticeably spaced apart. Interwell distances vary between several hundreds of ft to over a thousand ft (see later).
Figure 1. (a) Aerial view of the RELLIS area (left image) highlights oil well sites (yellow circles); (b) Map view (right image) shows a more abstract schematic of the campus, with oil sites highlighted. Our study presents evidence of pressure communication between wells hundreds to thousands of feet apart.
Our field study on the pressure communication between the wells of the individual companies was conducted using data provided by each of the operators (i.e., Austin Chalk and Eagle Ford leases, respectively). Well data are reported to the Texas A&M System in connection to their royalty share. Each reservoir is part of a split estate, which means that the mineral rights of the Austin Chalk and Eagle Ford Formation are leased to two different operators.
Operators are pragmatic and have no incentive for judicial recourse in case of subsurface trespassing, which refers to the potential impact on mutual well productivity due to engineering interventions in adjacent petroleum reservoirs. Prior proceedings in the Texas High Court of Justice between adverse operators has declared the mutual responsibility to resolve any dispute lies with the individual operators .
This study explains the reservoir setting and well layout, initial pressure state in both reservoirs (Eagle Ford and Austin Chalk), and then proceeds to report the pressure data collected. Our study confirms there exists no pressure communication between the two reservoirs, either prior to, or after the fracture treatment. However, a significant temporal pressure response was measured in the Austin Chalk legacy wells during both the 2017 DFIT and the zipper frac operations in the Eagle Ford landing zone. We analyze the initial pressure state, temporal changes induced during, and the final pressure state in each reservoir after the interventions. The second part of the paper presents a conceptual model that can explain the physical process of the interwell pressure communication based on the field pressure data analyzed in the first part of our study.
Project Overview and Data Acquisition
We have collaborated extensively with several operators in the Eagle Ford Formation below the RELLIS Campus and used the provided field data to develop pressure depletion models [2,3] and production forecasts . However, the overlying Austin Chalk Formation was developed in the early 1990s and although some logs are available from nearby wells in the formation, few details other than production data can be obtained for those older wells.
Six horizontal legacy wells, each with 4000 ft lateral length in the Austin Chalk reservoir landing zone beneath the RELLIS campus have either ceased to produce (3) or are marginal producers (3). These wells, named “Riverside 1 to 6” (or more simply R1 to R6) form the principal object of our study. The drilling and completion of two new wells in the Eagle Ford, with zipper fracking under extremely high hydraulic pressures used during fracture treatment of two Eagle Ford wells drilled in Nov/Dec 2017, provided a unique opportunity to gather pressure response data in the overlying Austin Chalk Formation via five pressure gauges, each mounted on a different Austin Chalk Riverside well.
Well Location and Trajectories
The Texas A&M University System administers the mineral rights of the RELLIS Campus in College Station, Texas, which includes the Eagle Ford shale, Austin Chalk and Buda Limestone plays that produce oil, and to a lesser degree, some associated natural gas. The development of the hydrocarbon plays (involving drilling, completion and necessary production operations such as shut-ins, artificial stimulations, including hydraulic fracturing and well workovers) is leased out to private operators. Our field study on the pressure communication between the wells of the individual companies was conducted using data provided by the various prior and current operators (i.e., for Austin Chalk and Eagle Ford leases, respectively). Well data are reported to the Texas A&M System in connection to their royalty share.
The RELLIS lease area hosts 12 wells drilled and completed during different epochs. Table 1 displays the names and parameters of the wells studied, with the well specifics based on data from the Texas Railroad Commission. The six Austin Chalk legacy wells are currently owned by E2 Operating, a subsidiary of Exponent Energy, which acquired the wells in 2014 from a bankruptcy sale. There have been many changes in ownership of the Austin Chalk wells, which were first completed in 1990s, not further elaborated here, as can be traced via the Texas Railroad Commission. The more recently developed six Eagle Ford wells are currently operated by Hawkwood Energy (Table 1), who bought the lease from Halcon Resources in 2017. Subsurface and production data were provided to us by various lease operators (i.e., E2 operation, Halcon Resources and Hawkwood Energy). All the companies mentioned in Table 1 are oil and gas operators in Brazos county, Texas, USA.
Table 1. Dates of completion of wells in the RELLIS lease area.
A diagram of the well trajectories completed in the RELLIS lease area is shown in Figure 2a. Eagle Ford Wells H2 and H3 were completed most recently (2017) and can be considered the child wells of parent Wells R, O, M, H1, all of which were completed in 2014. Figure 2b illustrates the chronology of the development of the RELLIS lease area considered in our study. The dates of first production for the Eagle Ford Wells are the same as the dates of completion reported in Table 1.
Figure 2. (a) RELLIS wellbore trajectories. The white arrows represent the surface location of each well. The dotted outline represents the landing zone. The rectangular panel shows the portion of the gun barrel view introduced in Section 2.3. Wells labeled R, O, M, H1, H2, H3 are completed in the Eagle Ford shale and wells labeled 1 to 6 are the Riverside wells completed in the Austin Chalk. The two Eagle Ford shale child wells, H2 and H3, are drilled from approximately the same location on the surface, and Wells H1, H2, H3 and O are mutually parallel. Wells H2 and H3 are 350 ft deeper at the toe (8450 ft) than at the heel side (8100 ft), due to a gentle slope of the producing landing zone of the wells. (b) Chronology of development of RELLIS oil and gas lease area. Dates of well completion are displayed. The black bar represents a time lapse from 1996 to 2012. The Eagle Ford Wells (H1, H2, H3, R, O, M) are much younger than the Austin Chalk Wells (R1–R6) which have been operational for over 25 years.
Prior to the recent rush to develop the Eagle Ford shale with modern multistage hydraulic fracturing techniques, only the Austin Chalk was developed in the RELLIS lease, because it is naturally fractured and production required only little well stimulation. Production for all the Austin Chalk wells started nearly three decades ago, first reported as of 1 July 1991, which is when the common production facility was completed for use by Well R1 initially.
Each of the six Austin Chalk wells was fractured as a single stage with 7-inch casing and 30,000 bbl water, 11,000 lbs of diverter, and 18,000 gal of 15% hydrochloric acid. Additional completion data was not available. In 1992, the Austin Chalk Formation in Texas had a total of 4425 wells completed, which produced 330 million bbl of cumulative oil . A more recent well count gives the 9500 wells in total and a cumulative production of 1.7 billion BOE . The Austin Chalk, however still contains a large amount of unrecovered hydrocarbon resources, so the expansion of exploration in this formation could prove to be very profitable .
Initial Pressures of the Austin Chalk and Eagle Ford Hydrocarbon Reservoirs
Three of the six Austin Chalk wells have been recently plugged and abandoned (R2 and R5 in January 2018; R6 in spring 2019) by the operator to make room for building operations. Over the course of their lifespan from July 1991 to January 2018 (28 years of production), the six Austin Chalk wells have cumulatively produced 1 million bbl of oil and 3.5 bcf of natural gas. Wells R2, R5 and R6 were already not producing for several years and remaining producers R1, R3 and R4 were shut-in during the fracture treatment of Wells H2 and H3. Currently, of the three remaining Austin Chalk wells, one is inactive (not pumping) and the two active ones only produce a marginal 2–3 bbl/day.
Figure 3. (a) Cumulative production of the six Riverside wells (R1-R6). (b) Monthly production decline curves for six Riverside wells. Oil (blue curve) is measured in bbl and gas (orange curve) in Mcf.
Knowing the pressure of the Austin Chalk reservoir space immediately prior to the fracturing operation on Nov/Dec 2017 is relevant in order to better understand how the hydraulic pressure of Eagle Ford well stimulation communicated with the ambient pressure in the Austin Chalk reservoir space. The pressure depletion in the Austin Chalk reservoir just before the fracturing of Wells H2 and H3 can be estimated based on historic production and decline curves using production data from Texas RRC online.
Initial Pressure in the Austin Chalk Formation
All six original Austin Chalk wells (R1–R6) were connected to a single production gathering system. The cumulative hydrocarbon output of the aggregated production system since first production started is graphed in Figure 3a. The monthly decline of the hydrocarbon production over the 27-year well-life is separately plotted in Figure 3b. Note that all the gas produced in this formation is dissolved gas. For most of its production history, there existed no free gas under reservoir conditions since the reservoir pressure was above its bubble point pressure such that there was only liquid in the formation. Further, low productivity of Austin Chalk can be attributed to reduced reservoir pressures and dissolved-gas-drive mechanisms . The Riverside wells were operated by pump jack for most of their production histories.
Using monthly production data, the reservoir pressure near the Austin Chalk wells at the time of the fracture treatment in Wells H2 and H3 was modeled based on the material balance technique outlined in , reproduced in Equation (1). The detailed methodology and parameters used are explained in Appendix A. Using monthly production data, the reservoir pressure near the Austin Chalk wells at the time of the fracture treatment in Wells H2 and H3 was modeled based on the material balance technique outlined in , reproduced in Equation (1). The detailed methodology and parameters used are explained in Appendix A. The pressure depletion curves obtained are shown in Figure 4a. Keeping all other variables constant, a sensitivity analysis for the drainage area is presented in Figure 4b, which shows that the effect of depletion is stronger for small drainage areas. The logarithmic correlation obtained indicates that the pressure depletion effect is dependent on the amount of hydrocarbon in place, which can be represented through drainage area, (with all other variables kept constant). The equation for original oil in place, (𝑁) is presented in Equation (2). Details of the nomenclature/parameters used in Equations (1) and (2), assumptions made and method of depletion calculation are further discussed in Appendix A:
Figure 4. (a) Pressure depletion curve for the Austin Chalk Formation with an assumed drainage area of 2000 acres. The depletion rate declines after long term production. (b) Sensitivity analysis for the effect of drainage area on reservoir pressure depletion. A strong logarithmic correlation is obtained.
Based on Figure 4a, the current reservoir pressure of the Austin Chalk is estimated at 2354 psi, corresponding to an assumed drainage area of 2000 acres, which is the approximate acreage of the RELLIS campus lease area . This value will be used in building a pressure response model (See Section 4.4).
Initial Pressure Eagle Ford Formation
Although the Eagle Ford shale is an ultra-low permeability formation with negligible natural fractures in the area studied, the occurrence of pressure communication between Eagle Ford shale and the naturally fractured Austin Chalk would mean the fracture stimulation pump schedule may need adjustment when optimizing the fracking process.
The wells recently completed in the Eagle Ford Formation confirmed that the initial reservoir pressure remained intact [2,3], despite nearly three decades of oil and gas extraction in the overlying Austin Chalk Formation. The initial reservoir pressure of the Eagle Ford prior to first well completion in 2014 (Table 1) was estimated based on history matching to be 4891 psi .
The initial pressure in the Eagle Ford of 4891 psi is higher than the depleted state of the Austin Chalk, at 2354 psi. Interestingly, the lower pressure allows fluid to migrate to the Austin Chalk Formation during the fracking of wells in the Eagle Ford. We will further analyze the pressure communication between the Austin Chalk and Eagle Ford reservoirs during the 2017 fracture treatment.
Austin Chalk Pressure Gauges Monitoring Eagle Ford Zipper Fracking Operation
The main focus of this study is on the analysis of pressure response data of shut-in Austin Chalk wells during zipper fracking of the two nearby Eagle Ford wells. A gun barrel view of all the wells below the RELLIS lease area is shown in Figure 5a to display well spacing and pressure gauge placements. Well spacing estimates are based on each well’s trajectory. The Eagle Ford wells were drilled such that all wellbore trajectories were mutually parallel and in the direction of minimum horizontal stress of the region, which is assumed to coincide with the direction of the regional dip towards the Gulf of Mexico.
Eagle Ford well spacings could therefore be easily measured from a wellbore trajectory map. The Austin Chalk legacy wells spacings were estimated on a line of best fit perpendicular for each wellbore, extrapolating for R3 and R4. While reasonably accurate, the well spacings should therefore be taken as only estimates, as an uncertainty of ±100 ft exists.
Figure 5. (a) Pressure sources and positions. Gun barrel view of all the hydrocarbon wells completed in the RELLIS lease area used for our pressure communication study. Red arrows indicate possible connections between pressure signal source and the observation pressure gauges, which monitored the annulus pressures on wellheads of Wells R1-R6. No pressure gauge was mounted on Well R3. Section is taken from panel in Figure 2a from South West to North East as outlined. Well R6 is outside the section and is therefore not shown in gun barrel. Well spacings are estimated using Well R3 as a reference line. The horizontal axis represents spacing relative to the midpoint of Wells H2 and H3. Vertical axis represents true vertical depth, and is exaggerated 6.6×. (b) Pressure signal timeline. Example of timeline depicting the relative durations of the first 8 stages of the zipper frack operation for Wells H2 and H3 (around the clock). The inset table represents the order of events in the operation. There was a slight delay at the start of the project and Stage 1 in Well H2 began almost half a day later than in H3. The remainder of the procedure experienced no delays and the zipper frack pattern occurred with no incidents reported.
Eagle Ford parent wells (R, O, M, H1) were drilled in 2014 (Table 1). Eagle Ford child Wells H2 and H3 were drilled and completed in fall 2017, and were closely monitored for response in neighboring wells. In the case studied here, the operators adopted an optimized fracking approach called zipper fracking, which involved the staggered/alternating stimulation of the two wells on a stage by stage basis from toe to heel , as shown in the timeline drawn in Figure 5b. This is not to be confused with simultaneous fracking (“Simulfrac”), a similar technique in which the two wells are fractured simultaneously, saving valuable time for operators .
In both cases, a primary aim (in addition to saving operation time and cost) is to create a network of complex hydraulic fractures, which can maximize stimulated rock volume, instead of fracturing linearly as with the traditional method . Figure 5b further shows that there is no overlap between the durations of any two stages, so each stage acts as a distinct source for pressure response. Although Figure 5b shows only the timeline of the first 8 stages of Wells H2 and H3, we used and analyzed the pressure signals of all of the combined 101 stages involved in the fracturing operation (see Section 2.4 and Section 3.1).