An extensive laboratory program was conducted for the measurement of the interfacial tension between CO 2 and water or brine covering the ranges of (2 to 27) MPa pressure, (20 to 125) °C temperature, and (0 to 334 010) mg • L -1 water salinity. The laboratory experiments were conducted using the pendant drop method combined with the solution of the Laplace equation for capillarity for the profile of the brine drop in the CO 2 -brine equilibrium environment. The analysis of the resulting set of 378 IFT measurements reveals that: (1) under conditions of constant temperature and water salinity, IFT steeply decreases with increasing pressure in the range P < P c and mildly decreases for P > P c with an asymptotic trend toward a constant value at higher pressures; (2) under the same conditions of constant pressure and temperature, IFT increases with increasing water salinity, reflecting decreasing CO 2 solubility in brine as salinity increases;(3) the dependence of IFT on temperature is more complex than that on either pressure or salinity, depending on the CO 2 phase. For T < T c , IFT increases with increasing temperature, and around the critical point (T ≈ T c ), IFT significantly decreases (believed to be associated with the fact that at T c the IFT between CO 2 liquid and vapor phases tends to zero) and then increases again with increasing temperature for T > T c with an asymptotic trend toward a constant value for high temperatures. The dependence of IFT on pressure, temperature, and water salinity for CO 2 and water/brine systems can be well approximated by a power function of pressure whose coefficient and exponent depend on temperature and water salinity. These results indicate that, in the case of CO 2 storage in deep saline aquifers as a climate-change mitigation strategy, the formation water displacement by injected CO 2 during the injection (drainage) phase of CO 2 storage and the possible subsequent CO 2 displacement by invading brine during the CO 2 migration (imbibition) phase depend on in situ conditions of pressure, temperature, and water salinity through the effects that these primary variables have on the IFT between CO 2 and aquifer brine.

No abstract

Injection of CO2 has been used for enhanced oil recovery (EOR) in many light and medium gravity reservoirs. Consequently, sequestration of CO2 in oil reservoirs in conjunction with CO2-EOR is a method that is under consideration for reducing CO2 emissions into the atmosphere. Many oil reservoirs are underlain by an aquifer, and EOR processes often involve water-alternating-gas (WAG) processes. Proper understanding of the relative permeability character of such systems is essential in ascertaining CO2 injectivity and migration, and in assessing the suitability and safety of prospective CO2 injection and sequestration sites. While many measurements exist for CO2-oil systems, very few data, if any, exist for CO2-brine systems. This paper provides an analysis of brine-CO2 interfacial tension (IFT) measurements that were conducted for equilibrium brines and CO2 at reservoir conditions, and the detailed 700 MPa mercury-injection capillary pressure tests conducted on all rock samples to determine specific pore size distributions. Three sandstone and three carbonate potential sequestration zones in the Wabamun Lake area in Alberta, Canada, were evaluated, together with a caprock shale. This data set has specific application to the study of the behavior of injected CO2 in contact with bottom water or water-saturated zones that may be encountered in CO2-EOR projects, as well as for CO2 sequestration in deep saline aquifers. The analysis shows some correlation between the CO2-brine IFT, pore size distribution of the intergranular porous media and CO2-brine relative permeability. However, due to the high degree of variability in the pore system character of the different sandstone and carbonate facies tested, additional, better-controlled comparative tests are required to validate these trends. The hope is that, ultimately, compilation of more extensive datasets will allow appropriate selection of proper CO2-brine relative permeability relationships at reservoir conditions for intergranular sandstone and carbonate formations on the basis of relatively simple measurements of pore system geometry and IFT. These data will also provide a valuable tool for the estimation of CO2-brine relative permeability for the simulation and evaluation of intergranular sandstone and carbonate formations on a worldwide basis.

No abstract

No abstract

Very low in situ permeability gas reservoirs (Kgas<0.1mD) are very common and represent a major portion of the current exploitation market for unconventional gas production. Many of these reservoirs exist regionally in Canada and the United States and also on a worldwide basis. A considerable fraction of these formations appear to exist in a state of noncapillary equilibrium (abnormally low initial water saturation given the pore geometry and capillary pressure characteristics of the rock). These reservoirs have many unique challenges associated with the drilling and completion practices required in order to obtain economic production rates. Formation damage mechanisms affecting these very low permeability gas reservoirs, with a particular emphasis on relative permeability and capillary pressure effects (phase trapping) will be discussed in this article. Examples of reservoirs prone to these types of problems will be reviewed, and techniques which can be used to minimize the impact of formation damage on the productivity of tight gas reservoirs of this type will be presented.

Introduction Formation damage is a hot topic these days-with justifiable reason, as more operating companies move to the exploitation of more and more challenging oil and gas reservoirs in tighter, deeper, and more depleted conditions. Disappointing production or injection results from an oil or gas well can be related to a number of factors which may be difficult to diagnose. Some of these may center about poor inherent natural reservoir quality characteristics, others about mechanical considerations surrounding the condition and type of the wellbore obtained, and still others under the nebulous catch-all of "formation damage" which often (and sometimes unjustly) absorbs the majority of the blame for the poor results of many projects. Formation damage in oil and gas wells is difficult to quantify in many cases. This is due to the inability of the reservoir engineer to retrieve exact samples and conduct detailed measurements on the area of interest, usually represented by a volume of rock surrounding the wellbore which is generally several thousand meters below the surface of the earth. However, ongoing research over the years has allowed the development of a variety of techniques allowing the use of the available information to obtain a much better indication f the type and degree of damage which different reservoirs may be sensitive to, thereby adjusting operating practices to attempt to minimize or reduce these permeability reducing factors. This data would include information such as production and pressure data, pressure transient data, log analysis, fluid and PVT data and core, cuttings, and special core analysis data. The subject of this brief article is to provide a synopsis of some of the types of formation damage which commonly present themselves as problems for many oil and gas producing projects, and review some of the associated technology being used to overcome these problems. How Much of a Concern is Formation Damage? A technical definition of formation damage would be "any process that causes a reduction in the natural inherent productivity of an oil or gas producing formation, or a reduction in the injectivity of a water or gas injection well." Although the drilling process often bears the brunt of the blame, formation damage can occur at any time during the life of a well including completion, production, stimulation, kill, or workover operations. Often the problem is ignored due to a combination of ignorance and apathy with the common rationale that "We don't care about formation damage in this reservoir-we can always fracture through it." Surprisingly, this pretense may make sense in certain situations, particularly when the formation is of such low inherent quality that it is obvious the flow area and driving differential pressure available for production present in a normal cased and perforated or open hole completion are insufficient to sustain economic production rates, even with a totally "non damaged" well.

Proper modeling of the multiphase flow of supercritical CO 2 in deep saline aquifers for CO 2 sequestration (both cycles of drainage during injection and imbibition during CO 2 migration) is critical in being able to understand and predict both the short and long term fate of the injected CO 2 over extended time periods (hundreds to thousands of years). Current numerical models require the use of accurate two-phase CO 2 /brine relative permeability data at representative in-situ conditions in order to be able to accurately conduct these calculations. However, there are virtually no published data in the literature on the high temperature and pressure displacement character of CO 2 /brine systems in actual reservoir rocks, except for the data published by the authors in the June 2008 issue of the SPE Reservoir Evaluation and Engineering Journal. That data set, although it included a few carbonate cases, contained mostly measurements on clastic rocks. This paper presents a new set of nine relative permeability measurements (both drainage and imbibition) for carbonate rocks (limestone and dolomite) of higher permeability values than those in the initial work (which are thus more likely to be representative for candidates for CO 2 sequestration in deep saline aquifers). The new data set to be presented includes also pre and post-test CAT-scan imaging of selected samples to illustrate potential effects of CO 2 contact on potentially soluble carbonate matrices. The paper compares the new data set of measurements for carbonate rocks with the limited set of data available for carbonates from the previous work, and attempts to determine if specific relative permeability and residual saturation trends can be defined based on other rock characteristics that are easier to measure in routine core analyses, to allow extension of the data set to other carbonate facies elsewhere which have not been tested.