Study of Carbonate Reservoirs Examines Fines Migration in CO2-Saturated-Brine Flow
A high-carbon-dioxide (CO2) carbonate gas field offshore Sarawak, Malaysia, is scheduled for development. Reservoirs in this region have an average clay content of 8%; more than 50% of this clay content is migratory illite, and 15% is migratory kaolinite.
A high-carbon-dioxide (CO2) carbonate gas field offshore Sarawak, Malaysia, is scheduled for development. Reservoirs in this region have an average clay content of 8%; more than 50% of this clay content is migratory illite, and 15% is migratory kaolinite. Therefore, fines migration exacerbated by this low-permeability rock becomes a potential production and injection problem. A study was conducted involving rock mineralogy and dynamic flow to evaluate factors contributing to potential fines-migration damage within the production and injection interval.
Migration of fines is associated with oil and gas production in sandstones as well as carbonate reservoirs. Fine particles located on the surface of rock grains are affected by adhesion, drag, and electrostatic and gravitational forces. Drag and lifting forces detach the particle, whereas adhesion, electrostatic, and gravitational forces press the particle to the surface. Generally, the main sources of movable fine particles in sandstone reservoirs are kaolinite and illite clays. Kaolinite particles are flat plates usually stacked in the form of booklets. The surface area of clay minerals, for example, typically is large because of their structure and small size and is more reactive and prone to mobilization and migration.
Once mobilized, the fine particles are retained by size exclusion if their size exceeds the pore-throat size of the matrix. Fines damage also occurs when several small fine particles reach a larger pore throat at the same time and compete for passage through the throat with the result of bridging and sedimentation.
Usually, in the case of gas/water flow, the fines move with the wetting water phase. However, fines movement taking place before water movement has been observed in a number of gas reservoirs. The in-situ mobilization and migration of fines without a mobile wetting phase is primarily caused by hydrodynamic drag that exceeds the critical rate to mobilize the fines. It has long been realized during corefloods that colloidal controlled release of particles leading to fines migration may be caused by salinity change following flow rate that causes the fines to bridge at the pore throat. Generally, a decrease in salinity or an increased rate of salinity change leads to particle mobilization. This decrease in permeability caused by decreasing salt concentration has been found to be nonmonotonic.
In this study, the fines-migration potential of a high-CO2-content gas field is investigated. The carbonate reservoir is located in a platform reef environment at a water depth of 80 m. The reservoir is a carbonate structure with dimensions at the fluid contact of approximately 11×8 km, with the hydrocarbon trapped geologically through a four-way dip closure. The maximum hydrocarbon column is 483 m, with the interpreted free-water level located at 2193 m true vertical depth subsea. The carbonate gas reservoir can be subdivided into three formations, subsequently addressed as S1 to S3, with S1 being the lowest in the stratigraphy and S3 the highest.
Materials and Methods
To determine the critical rate of fines movement for this work, corefloods were performed at increasing rate stages with CO2-saturated brine as well as hydrocarbon gas. Mineralogy analysis of S3, S2, and S1 formation rock was conducted using X-ray diffraction (XRD) to determine type, amount, location, and morphology of clays. Pore-throat-size distributions were determined through mercury-injection capillary-pressure (MICP) tests for pore-level characterization of the rock. Total suspended solids (TSS) were measured during each incremental rate stage, and the effluents were analyzed. Coreflood tests were performed with supercritical CO2.
Core plugs of 1-in. diameter and 2-in. length were selected for the study after initial scans confirmed the integrity of the core plugs and the absence of fractures. MICP experiments were performed for selected samples at injection pressures of up to 60,000 psi. Pore-size distribution and permeability distribution curves were determined. The brine composition applied for the study is based on the water analysis from formation water of the reservoir and was simulated to match downhole conditions. The water can be characterized as sodium-chloride in type. The total-dissolved-solids concentration of the formation water is approximately 7550 mg/L.
The sulphate concentrations were reduced to zero in the brine to avoid sulphate forming scales during the experiment. The corefloods were run under the following conditions:
- Overburden pressure: 3,172 psi
- Pore-line pressure: 1,450 psi
- Temperature: 136°C
The net effective stress of 1,722 psi resulting from these conditions was applied on the basis of the existing geomechanical model of the reservoir. The temperature is representative of the average reservoir temperature of the production zone. The corefloods were performed at increasing rate stages, with each rate stage representative of a different distance to the wellbore on the basis of gas-production rates of 200 MMscf/D. TSS was determined from the corefloods by weight measurement at each rate increment before and after the coreflood.
Results and Discussion
The results presented here cover the work from four corefloods. XRD analysis revealed that these formations have an average of 50 wt% illite (considering total clay fraction), 15 wt% kalonite, 9 wt% chlorite, and 6 wt% smectite (Table 1). The clay content reaches its highest values further up in the stratigraphy toward the seal.
Two corefloods were performed with hydrocarbon gas and two with CO2-saturated brine. The mean hydraulic radii from the MICP of the samples varied between 2.7 to 7.1 μm, with more than 70% of the permeability associated with pore sizes greater than 10 μm. The 10-, 50-, and 90-μm pore-throat size values from the core plugs measured were 5–15 μm (D=10 μm), 1–9 μm (D=50 μm), and 0.02–3 μm (D=90 μm). All pore-size distribution curves are bi- to multimodal, indicating the considerable heterogeneity of the carbonate reservoir (Fig. 1).
Corefloods with hydrocarbon gas showed permeability recovery to 93% of baseline conditions at flow rates up to 600 mL/h. These results demonstrated that permeability values recovered almost fully compared with baseline levels. Differential pressures during each rate stage reached a stable value, indicating that no progressive formation damage occurred during each rate stage.
Overall, the amount of expelled solids for all the tests was not very high, with TSS concentrations of up to 58 mg/L. The expelled solids are made up primarily of silicate fines such as clay minerals. The clay particles were typically small to medium, ranging from approximately 5 to 50 μm, and having angular to subangular morphology. Considering the mean hydraulic radii of the pore throats and the size of the fines, the potential for formation damage caused by fines migration is expected.
Corefloods with CO2-saturated brine showed permeability recovery to 63% of baseline conditions at flow rates up to 1,800 mL/h. Stable differential pressures were reached again. The results demonstrated that permeability values declined during rates up to 600 mL/h. At the flowrates of 1800 mL/h, permeabilities increased again to 75% of baseline levels, possibly because of erosion of the core face, which was confirmed from digital images taken before and after the corefloods. An increase in flow rate did not correspond to an increased level of TSS released. The TSS concentrations showed a decreasing trend with time, indicating particle capture.
The results demonstrate that fines migration in carbonates can be an issue. A high potential for fines migration in this type of carbonate system exists for CO2-saturated brine flow. The critical rate for fines movement determined from the corefloods was 120 mL/h. There is a less-significant formation-damage potential for dry CO2 flow. It is expected that fines migration would only begin to affect production at a later stage in the field life, once water production from the reservoir increases.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 189569, “Fines Migration During CO2-Saturated Brine Flow in Carbonate Reservoirs With Some Migratory Clay Minerals—Malaysian Formations,” by Y. Sazali, Petronas; S. Gödeke, SPE, Universiti Brunei Darussalam; W.L. Sazali and J.M. Ibrahim, Petronas; G.M. Graham and S.L. Kidd, Scaled Solutions; and H.A. Ohen, SPE, HPO Global Resources Ventures, prepared for the 2018 SPE International Conference and Exhibition on Formation Damage Control, Lafayette, Louisiana, USA, 7–9 February. The paper has not been peer reviewed.