Results of numerical investigations at SECARB Cranfield, MS field test site

GCCC Digital Publication Series #09-10

Jean-Philippe Nicot Jong-Won Choi

Timothy A. Meckel Kyung-Won Chang Susan D. Hovorka

Silvia Solano

Cited as: Nicot, J. -P., Choi, Jong-Won, Meckel, Timothy, Chang, C. Y., Hovorka, S. D., and Solano, Silvia, 2009, Results of numerical investigations at SECARB Cranfield, MS fielt test site, in Eighth Annual Conference on Carbon Capture and Sequestration: DOE/NETL, 11 p. GCCC Digital Publication Series #09-10.

Keywords: Field study-Cranfield-MS;Modeling-Flow simulation

CONFERENCE PROCEEDINGS

EIGHTH ANNUAL CONFERENCE ON CARBON CAPTURE AND SEQUESTRATION - DOE/NETL May 4 - 7, 2009

Results of Numerical Investigations at SECARB Cranfield, MS Field Test Site

Jean-Philippe Nicot, Jong-Won Choi, Timothy A. Meckel, Kyung-Won

Chang, Susan D. Hovorka, and Silvia Solano

Gulf Coast Carbon Center, Bureau of Economic Geology, Jackson School of Geosciences The University of Texas at Austin, Austin, TX, USA

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Abstract The Cranfield Field, MS is the site of the SECARB Partnership’s phases II and III. The 10,000 ft-deep reservoir produced ~62 MMbbl of oil and ~670 MMSCF of gas from the 1940’s to the 1960’s and is being retrofitted by Denbury Onshore LLC for tertiary recovery. CO2 injection started in July 2008 and has been followed by a still ongoing ramp up since then. The Cranfield modeling team selected the northern section of the field for development of a numerical model using the multiphase-flow, compositional CMG-GEM software. Model structure was determined through interpretation of logs from old and recently-drilled wells and geophysical data. PETREL was used to upscale and export permeability and porosity data to the GEM model. Early sensitivity analyses determined that relative permeability parameters and oil composition had the largest impact on CO2 behavior. The first modeling step consisted in history-matching the oil, gas, and water production out of the reservoir starting from the reservoir natural state and subsequent pressure recovery to determine its approximate current condition. The fact that pressure recovered in the 40 year interval between end of initial production and now helps in constraining boundary conditions. In a second step, the modeling focused on understanding pressure evolution and CO2 transport in the reservoir during Phase II. The third step consists in modeling Phase III CO2 injection in the brine leg of the accumulation to help in interpreting observations done in the injection zone. The overall match between observed data and model output of the CO2 injection is currently acceptable and is likely to improve as we learn more about the field.

Note: this is a preliminary version sent for final approval to DOE/NETL, SSEB, and Denbury.

Introduction The Cranfield, MS site has been chosen for large-scale CO2 injection as one of the Southeast Regional Carbon Sequestration Partnership (SECARB) Phases II and III test sites. SECARB is one of the seven U.S. Department of Energy (DOE) Regional Carbon Sequestration Partnerships and is led by the Southern States Energy Board (SSEB). The Cranfield field is an oil and gas accumulation, depleted after conventional production in the 1950’s; its Northern portion is currently under active CO2-flood and is operated by Denbury Onshore LLC (“Denbury”), from Dallas, TX. CO2 is brought to the site by pipe line from the Jackson Dome, a natural CO2 accumulation located in Central Mississippi ~100 miles away. Gulf Coast Carbon Center (GCCC) staff at the Bureau of Economic Geology (BEG), The University of Texas at Austin, in collaboration with many institutional and private partners, is in charge of setting up, performing, interpreting, and reporting on the two major tests to be concluded at the site. This paper documents some of the numerical simulation work being done in support of field activities. Modeling work on Phase III (the so-called “early test” because results will be used to inform a second SECARB Phase III test called the “anthropogenic test” slated to occur in a saline aquifer located underneath a coal-fired power plant along the Gulf Coast) has started and is in its preliminary stages. The Phase III injection site is located in the brine leg of the trap, on the Eastern boundary of the field (but still within the unitized domain), slightly outside of the oil rim and at an elevation below the oil-water contact. A total of 1.5 million tons of CO2 will be injected in 1-2 years. It follows that the Phase III test will occur in a saline aquifer but with unusual boundary conditions in term of pressure because of the presence of the oil and gas field. A particular topic of interest is the impact of having higher compressibility fluids nearby (but not in direct contact with CO2) on the future pressure history.

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Although a significant portion of the information presented here is relevant to Phase III work, this paper focuses on Phase II work (both phases occur in the same general vicinity). Technical focus areas of Phase II are: (1) documenting CO2 retention in the injection zone; (2) quantifying capacity; and (3) quantifying pressure response to injection. This test is also called the Gulf Coast Stacked Storage project to demonstrate the potential of a likely business model in which infrastructure needed for CO2 sequestration could be built and paid for by CO2-based Enhanced Oil Recovery (CO2-EOR) and then use to sequester CO2 in deeper formations. The active field portion of Phase II began in July 2008 when Denbury started injecting CO2 into the field oil rim. BEG had retrofitted an old production well (Ella G. Lees #7 –EGL7) before start of injection to serve as an observation well in both the injection formation and in a sandy unit located ~380 feet above it. More details about the monitoring experience can be found in Meckel et al. (2009).

The Cranfield reservoir is located a few miles East of Natchez, MS (Figure 1) and has produced oil and gas from 1943 to ~1965 (Mississippi Oil and Gas Board –MSO&GB–, 1966). It consists of a simple 4-way anticline overlying a deep salt dome, which had a large gas cap surrounded by an oil ring (Figure 2). The reservoir is in the lower Tuscaloosa Formation of Cretaceous age at depths of more than 10,000 ft. Phase II numerical model includes only the Northern section of the field consistent with Denbury’s sliding production schedule starting in the North but that will eventually cover the whole field.

Model Structure Reservoir Geometry: the model was built with the PETREL software making use of information from old and new wells as well as data from a proprietary 3-D seismic survey and then exported into CMG-GEM (Figure 3). 3-D seismic interpretation shows that the reservoir is composed of stacked and incised channel fills and is highly heterogeneous vertically and horizontally. It also shows that thickness variation of the key units is below the resolution of the seismic image, even using advanced techniques (Hovorka et al., 2009). The Tuscaloosa Formation overlies a regional unconformity with some paleotopography; valley-fill-fluvial conglomerates and sandstones are complexly incised and aggregate to form a sheet-like basal sandstone unit. Interpretation using seismic and open-hole SP-resistivity and porosity permeability data from historic side-wall cores confirms this heterogeneity, but it is of only modest use in developing needed reservoir models to extrapolate through the interval (Hovorka et al., 2009). A representative thickness of the hydrocarbon-bearing formation is ~60 ft.

Reservoir Properties: Due to the heterogeneous nature of the reservoir, both permeability and porosity are extremely variable (ranging from <1md to >1000 md and from <10% to >30%, respectively) and it is likely that several equally plausible permeability and porosity distributions would match pressure data. Average permeability has been described varying from 50 md (Hovorka et al., 2009) to 280 md (MSO&GB, 1966); current modeling tends to favor the former. This range of permeability is consistent with a series of interference tests performed by Denbury between injectors and producers. The base-case permeability field is derived from an analysis of permeability-porosity correlation of selected core data, the transform is then applied to all wells, interpolated between wells, and upscaled to the GEM grid. MSO&GB (1966) suggested a residual water saturation of 47%. For the imbibition processes, we assumed an oil residual saturation of 25% and a maximum residual gas saturation of 30%. Relative permeability curves follow a Brooks-Corey model. Two rock types were defined: “clay” whose capillary properties are such that, by design, CO2 cannot enter under injection pressure conditions and ‘sand” through which CO2 can migrate.

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Oil and Gas Composition: CMG-GEM was chosen for the simulations because it is a compositional model. The PVT module handles the partitioning behavior of the system components between oil and gas phases and its impact on flow properties of the system (density, viscosity). Initially there was a concern that the current oil composition would be different from the one documented in MSO&GB (1966) because the gas cap blow-down might have stripped the oil from its lighter components. This would have complicated the modeling of CO2 dissolution in the oil phase because the oil composition would have been more likely to be spatially variable. Thanks to Denbury’s recent sampling of tank oil and separator gas (Figure 4), it seems that historical and current oil compositions are similar justifying the use of a constant oil composition at initial time in the model.

Final Model Structure and initial conditions: all properties, including oil and gas saturations, were distributed assuming pre-production conditions respecting gas/oil and water/oil contact elevations.

History Match The purpose of the modeling is not to produce a perfect history match in order to generate oil production predictions but rather to allow us to put in context and understand observations gathered in the course of the SECARB project. Once the model cells have been populated with their initial values described in the previous section, the model equilibrates itself to steady state in a hypothetical long transient (thousands of years) to reproduce the desired initial conditions set as follows: (1) at hydrostatic pressure with no flow, (2) with the correct, observed phase contacts; (3) that include the right amount of hydrocarbons as given in MSO&GB (1966) [the so-called equilibration period]. The reservoir is then numerically produced, the gas cap blown down, [production period] and the pressure allowed to go back to hydrostatic during the 40 pressure recovery intervening years between end of conventional production and start of EOR injection [recovery period] before CO2 injection starts [injection period]. Results of the modeling of the production period were checked to be consistent with historical production of fluids, including water cut. Imaginary injection wells on the boundary of the models account for aquifer dynamics, injecting water needed to imbibe the reservoir and achieving return to hydrostatic conditions as observed when the wells were recently reentered.

The field was operated by a company that became Chevron and benefited from early unitization under a single operator. Operation decisions were made at the field level to recover as much hydrocarbons as possible in an organized fashion. The oil was produced first and the outgassed gas reinjected to maintain pressure (gas reinjection curve on Figure 5b). After reservoir pressure and production dropped, the operator experimented with water flood / water injection to maintain pressure (water injection curve on Figure 5a). As it did not work as expected (no uptick in oil production on Figure 5a), the gas cap was blown down (large pressure drop on Figure 5a and b). The reservoir produced ~62 MMbbl of oil and ~670 MMSCF of gas. The numbers have to be scaled down to account for the fact that only the Northern section is modeled in this work. Individual production through time for each well is not available, only overall production is. MSO&GB (1966) also suggested that Original Oil In Place (OOIP) is likely more than twice the amount recovered, consistent with generally observed relatively low recovery in heterogeneous formations. The amount of oil remaining in the subsurface is obviously the target of the EOR flood but, to this model, it also matters because of the strong affinity of CO2 for oil, impacting breakthrough time and observed pressure at the observation wells.

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The history match work also included numerous sensitivities analysis (see Nicot et al., 2009 for details) to rank poorly- or insufficiently-known parameters in term of their impact on pressure and breakthrough time during the CO2 injection period. Oil composition, absolute permeability, and relative permeability end-points were the most critical factors.

CO2 Injection Period CO2 injectors were progressively put online, starting in July 2008, and there are currently 8 of them located in the Northern section of the field totaling >24 MMSCFD. Oil is currently being produced through wells that were allowed to produce as soon as the pressure formation was high enough to lift the oil and maintain its flow to the surface (no pump). Pressure data have been collected from a number of wells through dip samples since injection started as well as from a dedicated observation well. CO2 breakthrough has not occurred at the latter yet but some of the other wells have started producing oil and CO2. In the initial modeling work, we began using a permeability field whose arithmetic average was given by MSO&GB (1966) at 280 md (“base-case”). This value was plausible because high permeability streaks have been observed in cores and well logs. However, it is likely that such observations probably biased high the average permeability put forward by the historical operator. Another possibility is that the northern section of the field has a lower than average permeability but a look at production history (not shown) tends to discount such a hypothesis. We were unable to reproduce pressure history unless permeability was significantly reduced either by assuming some horizontal anisotropy (that would be consistent with a fluvial depositional system) or by modifying the absolute permeability to levels consistent with Hovorka et al. (2009)’s statement. A decrease in porosity from the base case 25% also helped achieve a better match (Figure 6).

Conclusions In order to understand CO2 behavior during the injection period, we modeled the whole production history of the field starting with pre-development conditions. The formation containing the hydrocarbon accumulation is comprised of sediments deposited in a fluvial environment. This type of depositional environment is characterized by highly heterogeneous flow properties. The modeling team is still collecting useful field information but has started to converge on a model that will match well pressure and breakthrough time in the Phase II domain giving confidence that transfer of information to the Phase III area will equally lead to accurate predictions

Acknowledgements This study was conducted as part of the SECARB’s Phase II research project funded by the U.S. DOE/NETL under DE-FC26-05NT42590, and managed by Southern States Energy Board (SSEB). The Bureau of Economic Geology thanks project managers Bruce Lani and Gerald Hill for their continued support. We thank the Denbury Onshore LLC for allowing us access to field and data. We are also grateful to the Computer Modelling Group (CMG), Calgary, Canada, for giving us free access to their GEM software and to Schlumberger for discounted access to the PETREL suite software.

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References Hovorka, S. D., J.-W. Choi, T. A. Meckel, R. H. Trevino, H. Zeng, M. Kordi, F. P. Wang, and J.-P. Nicot, 2009, Comparing carbon sequestration in an oil reservoir to sequestration in a brine formation—field study, Energy Procedia, Vol. 1(1), Proceedings of 9th International Conference on Greenhouse Gas Control Technologies GHGT9, 16 - 20 November 2008, Washington DC, p. 2051-2056.

Nicot, J.-P., J.-W. Choi, K.-W. Chang, and T. A. Meckel, 2009, Report on SECARB Phase II Numerical Modeling, Cranfield Field, MS: final report in preparation

Meckel, T. A., S. D. Hovorka1, D. Freeman, and R. Blackmon, 2009, Continuous monitoring of reservoir fluid pressure for an industrial-scale CO2 injection: manuscript to be submitted

Mississippi Oil and Gas Board, 1966, Cranfield Field, Cranfield Unit, Basal Tuscaloosa reservoir, Adams and Franklin Counties, Mississippi, p.42-58.

Figure 1. Location map of the Cranfield field in southwest Mississippi straddling Adams and Franklin counties. Grey symbols are wells penetrating the Tuscaloosa-Woodbine Formations.

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Figure 2. Cranfield field showing oil rim and gas cap footprints, historical wells, and Phase II modeling area (red rectangle)

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Figure 3. Overview of model reservoir structure (viewed from the SE) showing location of the currently active eight injectors. Model includes the northern third of the field. Arrow shows north; colors show depth.

Composition of synthetic oil sample (G:O = 0.683:0.317)

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Figure 4. Composition of the synthetic reservoir oil composition based on the Denbury sample and MSO&GB (1966) data; raw data needed to be corrected from surface conditions in a process described in Nicot et al. (2009).

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(a)

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Figure 5. Historical information at Cranfield (modified from MSO&GB 1966). Plot (a) depicts the oil production peaking the late 1940’s and plot (b) displays gas production and reinjection.

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Figure 6. Comparison of field data pressure and modeling results. Field data match well one of the sensitivity case in which permeability and porosity have been reduced compared to base case (see text)

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