Introduction
The use of carbon dioxide (CO2) to enhance oil recovery (CO2-EOR) has been practiced for many years. However, it is only in the past decade that this use has been driven by the need to dispose of CO2 emanating from industrial processes. Stimulus to use CO2 to enhance oil recovery, as distinct from simply sequestering it in deep aquifers, has come from a combination of political pressure, regulatory requirements, and oil fields nearing their ultimate recovery by secondary recovery methods such as water flooding.
As with any industrial process, economics plays a vital role. In the case of CO2-EOR, this includes, among other aspects, the price of crude oil and the cost to deliver the CO2 to the reservoir, neither of which forms the purview of the work reported in the book. Rather, we report here the essential results of a monitoring pilot study in which CO2 was injected into the Upper Cretaceous Cardium Formation at the Pembina Field, Alberta, Canada.
The pilot site was investigated at three scales where the level of detail decreased with increasing areal extent. The regional scale comprised about 10,900 km2, the local scale covered 12 sections around the pilot site, and the pilot-scale was immediately adjacent to the observation, injection, and production wells. The regional evaluation provided the baseline geological, hydrogeological, stress regime, and potential for wellbore leakage of the section from the Precambrian basement to the surface. The local-scale study evaluated the geology, surface seismic and wellbore leakage. Geochemistry and reservoir attributes were determined at the pilot scale. Environmental monitoring took place at the local scale.
The Pembina Field is located in west-central Alberta about 100 km southwest of Edmonton. It is one of the most areally extensive conventional oil fields in North America, and represents the single largest conventional hydrocarbon reserve in Alberta. The most prolific unit is the Cardium Formation, which was discovered in 1953, with primary production beginning that year, and waterflooding in the late 1950s. At the end of 2007, 3199 wells had oil production reported from the Cardium Formation, and 1112 wells were reported as injection wells (of which only one was injecting CO2). Cumulative oil production to the end of 2007 was 199 × 106 m3 (1.26 × 109 bbls). Original oil-in-place is estimated at 1.24 × 109 m3 (7.78 × 109 bbls). The area occupied by the Cardium pools is 2,542 km2. Total production from both primary and secondary schemes is near the maximum recoverable reserves for the pool; hence tertiary oil recovery using CO2 is being evaluated with a pilot project operated by Penn West.
There are three essential features of any CO2-EOR operation that concern the public and which need to be addressed. Put simply: (1) will the reservoir hold and contain the injected CO2, (2) what are the long-term effects of the injection, and (3) how will the situation be monitored so that the environment is protected? Each of these features will now be addressed under the headings Capacity, Containment, and Monitoring.
Capacity
The Pembina Cardium Pool lies at a depth ranging from 1200 m on its eastern margin to 1800 m in the west and dips southwest at about 10 m/km. The Cardium Formation is underlain by 200 – 300 m of shales and overlain by 250 – 325 m of shales.
At the pilot site, the Cardium Formation lies at a depth of about 1600 m and near the middle of the 650 m thick Colorado Group shale. It comprises four permeable (three sandstones and a conglomerate) and three impermeable units. Most of the storage capacity is contained within the three sandstones.
An ECLIPSE based black oil model was developed for the study with the geological model provided by Penn West. The area selected for the modelling study is about 22 times the size of the CO2 pilot, and the grid coordinates were oriented so that one coordinate was aligned parallel to the northwest-southeast permeability trend. The geological model covered an area of about 3.2 × 2.5 km and was carved out for the simulation study.
History matches with the field production data for the primary depletion and waterflood history from 1955 to 2004 were quite good and the oil, water, and gas production matched to within 2% of the field data. A smaller sub-model was extracted from the larger model to achieve reasonable run efficiency, and was in the same area where Penn West is currently implementing an expansion strategy. The initial reservoir conditions for the smaller model were taken from the final results from the continuing waterflood simulation run with the larger model. Two field prediction cases were conducted with this smaller model: (1) baseline waterflood, and (2) 1:1 WAG injection.
The simulation run predicted a 9.8% net incremental recovery over the baseline waterflood case at a total hydrocarbon pore volume injection of 1.9. This is expected based on the relative permeability curves used in the modelling which has an irreducible oil saturation of 44% for the water flood, which reduced to 7% for the EOR flood. The predicted incremental recovery is substantial, indicating good performance and areal sweep of the WAG process. Only 18% of the injected CO2 remains in the reservoir occupying 15% of the pore space at the end of the EOR project, a result of recycling. Irreducible gas saturation varies from 5% (drainage) to 25% (imbibition) for an average residual CO2 saturation of 15%. Therefore, the CO2 remaining behind in the reservoir is close to residual saturation, confirming the efficiency of the EOR process. This corresponds to a CO2 storage capacity of 1200 tonnes/hectare based on a pool area of 0.95 km2. Although not considered, more CO2 could be injected into the reservoir. If the reservoir could be reduced to residual oil and water saturation, 83% of the pore space would available. As 15% is already occupied by CO2, 68% would be available for additional CO2. In total, 6640 tonnes of CO2 could be stored per hectare if all the mobile water and oil were displaced. Scaling up of this value to the cumulative capacity of all the Cardium oil pools by comparing areas and original oil-in-place values, results in a value of 250 (± 50) Mt CO2 assuming they all underwent CO2-EOR. The ultimate capacity of the Pembina Cardium pools could be over 1 Gt CO2, if CO2 injection is continued after EOR and optimized for CO2 storage.
In summary, the Cardium Formation reservoir is an excellent candidate for storing significant volumes of CO2. There is thus a huge potential for expansion of CO2 storage in the Cardium Formation throughout the Pembina Field, with thousands of wells drilled to date.
Containment
Migration of CO2 may be constrained by lithological (rock), hydrogeological (fluid), and geochemical factors, among others.
Rock Barriers
The Cardium Formation sandstones in the Pembina area lie within a thick section of Colorado Group shales. They form a reservoir that is isolated hydraulically from overlying and underlying aquifers and from the ground surface. Lateral containment of fluids is guaranteed by compartmentalization of the formation due to lateral lithofacies changes and sandstone pinch-out updip, towards the northeast.
The effectiveness and integrity of the overlying shale succession is vital to the long-term storage of CO2. Leakage through this shale is very unlikely because it is thicker than 300 m and separates two aquifers with significantly different regional pressure regimes.
Cap Rock Integrity
In situ stress and rock mechanical properties are important elements in evaluating the safety of CO2 injection and storage at sites. The minimum horizontal stress in the reservoir is significantly lower than the cap rock, which is favourable for fracture containment. Rock elastic properties suggest that conditions are also favourable for fracture containment, and that the cap rock is strong. The geomechanical behavior of the shale cap rock formations overlying the reservoir is characteristic of intact, strongly indurated shales, and will provide effective sealing capacity for the injection of CO2 at the operating injection pressures.
Fluid Barriers
The regional hydrostratigraphy was determined using drillstem tests and formation water analyses. The pressure conditions and flow patterns in the Cardium Formation are different from other strata in the Pembina area. The Cardium aquifer is oil-saturated and overpressured. Isolated Cardium sandstone bodies north and northeast of the Pembina Field form pools that are normally or underpressured. The wide range from underpressured to overpressured areas shows that intervening permeability barriers prevent pressure equilibration and fluid flow between both the various Cardium oil pools, and overlying and underlying aquifers, demonstrating the strong compartmentalization of the Cardium Formation.
The Cardium aquifer is replenished by fresh meteoric water only in the area where Cardium sandstones lie close to the ground surface, about 300 km northwest of the Pembina area. In the study area, original formation water with salinity between 25,000 and 38,000 mg/l is present only at residual saturation or in local pockets. The isolation and compartmentalization of the Cardium aquifer in combination with the salinity values suggests that the formation water is probably slightly altered Cretaceous seawater. Water flooding for secondary oil recovery has resulted in the partial displacement of oil by external water, usually less saline than the locally occurring pockets of original formation water.
In summary, the pressure regime in the Cardium aquifer, compared to adjacent aquifers, strongly supports the hydrogeological isolation of the Cardium aquifer, thereby assisting in containing injected CO2.
Well Integrity
Wells in the Pembina Field show a relatively low potential for leakage (compared with the Alberta average). Increased reservoir pressure or the addition of corrosive gases could make the potential for leakage significantly higher. Based on information available it appears that the wells in the Pembina Field can withstand the implementation of CO2-EOR or CO2 storage, although wells abandoned in the future should use a more robust downhole abandonment method than a bridge plug capped with cement. More study is required to determine the durability of Neat cement and bridge plugs to improve the confidence of these findings.
Geochemical Traps
Although most of the CO2 is trapped in the reservoir by residual and solubility traps in the short term, in the long term the CO2 will become trapped in a more secure geochemical form by ionic trapping (e.g., bicarbonate formation) and mineral trapping. Therefore, detailed knowledge of the reservoir mineralogy is critical in the geochemical prediction of short- and long-term storage potential. The three sandstones are compositionally and texturally mature, comprising predominately quartz and smaller amounts of lithic fragments (shale), feldspar, apatite, and mica. The interstitial shales and shale cap rock are made up of fine-grained quartz, feldspars, mica, and clay minerals. Finely disseminated pyrite and carbonate minerals are also present. The appreciable amounts of aluminosilicate minerals (feldspars and clays) within the three rock types indicate that mineral trapping of injected CO2 in new mineral phases could be a significant form of long-term sequestration.
Reaction path modelling with the geochemical code GAMSPath was used as a predictive tool to estimate that the host rock has the capability to chemically fix more than a third of the residually trapped CO2 through solubility, ionic, and mineral trapping.
Monitoring
Monitoring of fluid and plume travel may be considered at three levels: (1) operational (in the target unit), (2) verification (in and directly above the reservoir), and (3) environmental (at shallow depths and in the atmosphere).
Shallow (Environmental) Monitoring
Environmental monitoring around the pilot site included baseline studies on air emissions, subsurface soil gas, and groundwater. The soil gas isotopic composition suggests that the CO2 is of biogenic origin, although some may have resulted from a previous surface spill. The chemical composition of the groundwater, as well as estimates of annual variability, baseline mineral saturation status, and isotopic composition give no indication that there was any leakage of the injected CO2.
Seismic Monitoring
The results of the surface seismic program were not successful in delineating the lateral extent of the CO2 plume. The lack of a coherent anomaly at the reservoir zone is interpreted as due to (1) the confinement of the CO2 plume to the thin conglomerate high permeability channel and to thin Cardium sandstones with relatively high permeability and (2) the relatively small change in physical properties between the native reservoir fluids and the injected CO2. Seismic monitoring through vertical seismic profile surveys is necessary to map the CO2 plume in this thin reservoir. Importantly, the lack of a 4D seismic change above the reservoir indicates that the injected CO2 is not leaking through the cap rock into shallower formations.
Geochemical Monitoring
Fluids from eight production wells and the injection stream were sampled at the pilot site, with significant changes in the water and gas occurring shortly after the onset of CO2 injection for those wells on the regional fracture trend, whereas there was very little response in the ‘off fracture’ wells. Core from three distinct time periods: pre-water flood (1955), pre-CO2 flood (2005), and during the CO2 flood (2007) was obtained and analyzed. Detailed whole-rock analysis suggests that the three sandstones in the reservoir are texturally and compositionally similar, regardless of when the core was taken. Dissolution features, including the partial or complete removal of carbonate cements, were observed in all cores. Therefore, attributing dissolution features in the core which was exposed to CO2 is difficult due to the existence of pre-existing dissolution features related to formation diagenesis.
Equilibrium calculations using SOLMINEQ.88 demonstrated that the waters were generally supersaturated with respect to dolomite, with many of the waters from the ‘on-trend’ wells being also undersaturated with respect to calcite. This suggests that the waters produced from these wells are mixtures of fluids, some of which are more significantly affected by CO2 injection than others. Reaction path modelling using GAMSPath demonstrated that the dominant reaction controlling the water composition in the short-term was ion exchange reactions, coupled with calcite dissolution and CO2 transfer from the oil phase. Further modelling with the reservoir simulator GEM® provided insights into the coupled reaction/transport processes occurring in the reservoir. Although the modelling results obtained to date do not correspond closely with solution compositions observed in the field, the study demonstrates the potential of using integrating geochemical measurements with reservoir models as a means to improve understanding of flow and reactions involving CO2 in reservoirs under CCS activities.
Deep Observation Well
An important feature of the study was the availability of a deep observation well instrumented with three pairs of downhole pressure-temperature sensors, eight geophones, and two downhole fluid recovery ports. In addition, the special U-tube design for the recovery of reservoir fluids at the surface under reservoir conditions developed by the US Geological Survey was modified for use with water as a ‘push’ fluid. The fluid recovery system developed for this project was designed for permanent installation whereas the US Geological Survey system is run on packers and is a retrievable system.
Cement Sampling
Successful retrieval of cement samples through a steel core barrel has run into problems in the past because of the mechanical issues around drilling through steel casing and cement with a single bit designed to collect an intact core plug. A detailed program focused on bit design to define all the elements of a field program to successfully acquire downhole cement samples. It was shown to be feasible with some drill bits but more work is required to develop a commercial cutter.
The modelling of cement placement is important because improperly placed cement may allow leakage of reservoir fluids, including the injected CO2. Using CAD software and computational fluid dynamic design software, it was shown that the flow velocity of cement near cables is half that of the velocity for locations without cables. This means that cement displacement efficiency never reaches 100% near cables. Although these results are preliminary they have considerable implications for CO2 disposal in deep formations because application of the technology should allow the detection of channels in the placed cement through which leakage may occur.
Conclusions
The Pembina Field is an important target for CCS in Alberta because of the opportunity to combine CO2-EOR and CO2 geological storage, and because of its large size. However, the thickness of the storage unit is small and requires a large number of wells to effectively store the CO2 over the entire field. Given that there are already several thousand wells in the field, the costs to exploit the storage site may be attractive as long as the wells are not subject to degradation or can be mitigated at a reasonable cost.
The work completed for the pilot project supports development of this field for CO2 storage in partnership with EOR operations. Both capacity and confinement have been demonstrated, and injectivity is being demonstrated by the EOR operations. In addition, significant advances have been made in (1) the design and deployment of an observation well, (2) the design of a well-cement sampling system, (3) the design and deployment of an environmental monitoring system, (4) the use of vertical seismic profile surveys, and (5) the development of in situ tracers.