Reservoir Condition Corefloods Research Articles

The prospects and potential opportunities of low salinity water flooding for offshore applications in sandstones

Low salinity water flooding (LSWF) is an emerging enhanced oil recovery (EOR) technology with enormous potential for offshore applications in sandstones. The objective of this study is to provide a review on LSWF offshore field applications and summarize the key lessons learned. A review was also conducted on the capabilities of existing sulfate removal units (SRUs) for seawater injection in offshore fields. Furthermore, the potential of targeting offshore oil fields with de-sulfated seawater (DSSW) injection, either ongoing or planned, as primary candidates to switch over to LSWF EOR has been investigated.For LSWF field trials, the chance of success can be significantly improved when it is based on key laboratory screening tests such as reservoir condition corefloods. The LSWF field tests implemented in offshore fields mainly comprise of single well chemical tracer tests (SWCTT) and interwell trials. However, the reported interwell field trials are restricted to unconfined pilots, which makes the injection and production allocation difficult. Therefore, confined pilots are recommended for future consideration of LSWF field trials to provide better estimations on swept volumes and accurately determine the improvements in the displacement efficiency.Globally there are more than 80 sulfate removal units in operation for de-sulfated seawater (DSSW) injection in offshore waterflooding. All these offshore fields with DSSW injection either currently ongoing or planned can become potential candidates for screening and switch over to LSWF EOR for the following two reasons: (1) The divalent cations can act as bridges between negatively charged rock surfaces and negatively charged polar oil components to increase the oil-wet tendency. These bridges can become primary targets to be replaced by un-complexed cations in low salinity water for EOR. (2) The de-sulfated seawater injection processes can easily be switched to LSWF by retrofitting the existing sulfate removal units with reverse osmosis (RO) desalination systems and upgrading the facilities to handle larger water volumes. Such retrofitting is considered sufficient to generate low salinity water, which can bring significant gains to increase oil recovery with minimal additional investment. The availability of RO desalination systems on offshore platforms can also provide potential opportunities for the cost-effective implementation of tertiary chemical EOR technologies especially polymer flooding.The novelty of this study is that it provides useful guidelines for reservoir screening and offshore field implementation of LSWF processes. Also, the new potential of evaluating the offshore oil fields with existing DSSW injection for switching over to LSWF has been identified. These findings will have a potential impact on enhancing the LSWF prospects and opportunities for EOR in different offshore fields.

Experimental evaluation of carbonated brine-limestone interactions under reservoir conditions-emphasis on the effect of core scale heterogeneities

CO2 injection into deep geological structures is very often accompanied by chemical interactions between the host rock and injected fluids and/or the in-situ created solute (i.e. carbonated brine). In fact, the in-situ reactions are considered one way through which the injected CO2 may be trapped for perpetuity. Depending on the nature and mineralogy of the host rock formation, such reactions may eventually result in a degree of change in the petrophysical properties of the rock. Carbonate formations, due to the presence of highly reactive minerals in their composition, are expected to be more prone to such changes than their sandstone counterparts.This manuscript presents the results of an experimental study conducted to evaluate possible changes in the petrophysical properties of five heterogeneous limestone samples (calcite concentration >91wt%). The study includes five reservoir condition core-flood experiments (i.e. one per each rock sample) complemented by other laboratory measurements/analyses including porosity-permeability measurements, X-ray CT (X-ray Computed Tomography) and SEM (Scanning Electron Microscopy) imaging.The results show a significant increase in the post-flood permeability of 80% of the samples caused by the dissolution and removal of carbonate minerals. The X-ray CT images reveal signs of significant mineral dissolution and establishment of flow paths through the initial larger pores in the samples leading, eventually, to the formation of wormhole features along the length of the samples. On the contrary, reduction in permeability is observed in one sample which was a relatively long (15.8cm) composite sample consisting of two core segments placed one after the other in series. The other four samples were shorter with a nominal length of 6.4cm. This reduction in permeability is observed predominantly in the outlet segment. This change is thought to have been primarily caused by possible migration of carbonate fines released by mineral dissolution in the inlet plug of the long composite core and to a lesser extent by the precipitation of minerals dissolved and transported from the inlet plug. This hypothesis finds further support in the pre- and post-flood dry weight measurements as well as a post-flood SEM image of the plug which reveals signs of fines migration and mineral precipitation. Slight reductions in the porosity and pore sizes are observed in most of the samples. This is likely to have been caused by the combined effect of fines migration, possible mineral precipitation and physical compaction mechanisms. Mechanical compaction is further evident from the reductions in the physical dimensions of the samples.Overall, the results obtained show that the nature and degree of any change in the petrophysical properties of the rock samples vary to some degree from one sample to the next. This variation is found to depend on the significance and degree of dominance of the three mechanisms of mineral dissolution, mineral precipitation and mechanical compaction if they occur during the flooding process. The migration of carbonate fines also seems to be an important factor in shaping the post-flood sample properties. The presence of any initial core scale heterogeneity in the pre-flood samples is also believed to be a critical factor controlling the eventual outcome.

Relative Permeability Measurements for Post-Waterflood Depressurization of the Miller Field, North Sea

Summary This paper describes a determination of critical gas saturations and relative permeabilities relevant to the depressurization of the Miller field. A series of reservoir-condition coreflood experiments and associated numerical simulations is described. Three experiments were conducted with aged Miller core and fluids at 120°C. Each was comprised of a waterflood at about 414 barg, followed by depressurization at different rates. The laboratory data included extensive three-phase in-situ saturation measurements that were used to derive gas relative permeabilities through the simulations. The rate-dependent critical gas saturations varied between 0.06 and 0.21, and gas relative permeabilities of the order of 0.0001 were deduced. These laboratory results are consistent with published data and suggest that conventional Corey-type gas relative permeabilities are an order of magnitude too large and do not represent the depressurization process.

Scale-up of near-miscible gas injection processes; integration of laboratory measurements and compositional simulation

Results from laboratory PVT measurements, special core analysis studies, and reservoir condition core-flood studies were used to develop and test the accuracy of a compositional simulation model in predicting near-multicontact miscible gas flood performance at the laboratory scale. Excellent agreement was obtained between the core-flood measured recoveries and GOR and the compositional simulation model predictions. No history matching was required to obtain this result. The choice of PVT and special core tests were critical to our ability to model the near-multicontact miscible displacement process without history matching. This result provides a high degree of confidence in using the compositional simulation model in cross-section and 3D element models to predict field-scale performance. Cross-sectional simulation sensitivities were performed in a geostatistical model of a dipping reservoir. Gas-flood recovery was on par with water-flood recovery for this cross-section.

Simple Approach to the Cleanup of Horizontal Wells With Prepacked Screen Completions

Openhole completions with prepacked screens are increasingly the completion of choice for horizontal wells requiring sand control. For maximum productivity from these wells, preventing mud damage to the formation and the screen or removing it before bringing the well onto production is vital. A common industry approach to this problem is to displace the drilling mud to an aqueous clear fluid before production, typically followed by a breaker fluid. This paper details an alternative approach: bringing the well on without cleanup. The paper outlines the decision-making process, shows how the drill-in-fluid ad cleanup operations are designed, explains how laboratory resting can be used to support the design philosophy, and highlights that quality control of the mud system while drilling is critical to the success of such a well. Case histories in two very different reservoirs are presented that illustrate the success of this approach.

Comparison of Laboratory and In-Situ Measurements of Waterflood Residual Oil Saturations for the Cormorant Field

Summary Shell Expro and Koninklijke/Shell E&P Laboratorium (KSEPL) have been engaged in a multidisciplinary effort to deter mine the waterflood residual oil saturation (ROS) in two principal reservoirs of the Cormorant oil field in the U.K. sector of the North Sea. Data acquisition included special coring and testing. The study, which involved new reservoir-engineering and petrophysical tech niques, was aimed at establishing consistent ROS values. Reservoir-engineering work centered on reservoir-condition corefloods in the relative-permeability-at-reservoir-conditions (REPARC) apparatus, in which restoration of representative wettability conditions was attempted with the aging technique. Aging results in a con sistent reduction of water-wetness of all core samples. The study indicated that ROS values obtained on aged cores at water throughputs of at least 5 PV represented reservoir conditions. The petrophysical part of the study involved ROS estimation from sponge-core analy sis and log evaluation.

Formation Damage From Acid Treatments

Summary Well treatments with only HCl are potentially damaging in formations that contain aluminosilicate minerals (clays, feldspars, and micas) because HCl reacts significantly with aluminosilicates, leaching aluminum and forming hydrated silica. Fluid flow past leached mineral particles liberates mineral fragments and amorphous silica within the pore network. These fines can block pore throats, reducing the rock permeability. Both field data and reservoir-condition coreflood test results are consistent with this chemical reaction and permeability impairment mechanism. The average permeability reduction in our corefloods was 35%.

Magnus Field: Surfactant Stimulation of Water-Injection Wells

Summary Water-injection wells in BP's Magnus field are located updip of the oil/water contact (OWC) because of poor aquifer injectivities. A pilot project was undertaken to increase water-injection rates by improving near-wellbore relative permeabilities to water by use of a surfactant to reduce residual oil saturations. This paper discusses the laboratory reservoir-condition coreflood tests, the field monitoring during surfactant treatment, and an interpretation of the success of the project.

A Laboratory Study of Wilmington Tar Zone CO2 Injection Project

Summary We conducted a laboratory study of heavy-oil recovery by CO2 injection to support-the Wilmington, CA tar zone CO2 injection project operated by Long Beach Oil Development Co. The study comprised (1) phase behavior of Wilmington tar zone reservoir oil and CO2, and (2) phase behavior of the oil and the refinery gas used for the field project, (3) viscosity measurements of oil/gas mixtures, (4) reservoir- condition displacements of oil by CO2 and by refinery gas, (5) equation-of-state characterization of phase behavior, and (6) computer simulation of gas/oil displacements. Saturation pressures'and swelling factors were measured for oil/gas mixtures, which showed that N2 is substantially less soluble in oil than is CO2. Viscosity measurements show that the viscosity reduction is a function of pressure and of the total gas dissolved in the oil. Four reservoir-condition corefloods showed that the recovery efficiency of CO2 is higher than that of the refinery gas for continuous or low WAG injection, and the recovery efficiency of the refinery gas at 1:1 WAG is about twice that of continuous injection. The corefloods were modeled with a finite-difference compositional simulator. Predictions agree with the experimental results.