Post-fracturing production data analysis indicates stimulation of some west Texas wells with surfactant additives did not enhance production as high as expected. Analysis of flowback and produced water for surfactant residues revealed 99% of surfactant was retained inside wells (
Literature precedent exists that polyelectrolyte (PET)-based SAs could significantly reduce surfactant adsorption not only onto a variety of outcrop minerals (Carlpool dolomite, calcite, kaolinite, Berea sandstone, Indiana limestone, etc.) and metal oxide nanoparticles, but also unconventional shale formulations in which surface area can be up to 700 m2/g. In this study, the adsorptions of surfactant and SA to proppants were first examined. Results indicate no adsorption was observed to proppant for both surfactants and PET-based SAs. SAs (0.5 to 1 gal/1,000 gal (gpt)) were then injected with surfactant (1 to 3 gpt) at an appropriate ratio into column-packed shale formulations (primarily composed of calcite, dolomite, quartz, illite, pyrite, and plagioclase feldspar) to investigate its effectiveness in controlling surfactant retention caused by adsorption. Laboratory testing revealed injection of 3 gpt mixture of surfactant and SA has a similar adsorption profile (surface tension as a function of time) as 3 gpt surfactant alone based on the dynamic surface tension measurement. Notably, the addition of SAs resulted in lower surface tension and enhanced hydrocarbon solubility; and thus, an improved oil recovery by surfactant was achieved as evidenced by the oil recovery tests. Additionally, 68% friction reduction of the fracturing fluid with surfactant and SA was sufficient for the field operation compared to the guar-based fluid used in the hydraulic fracturing applications.
As a result of the laboratory findings, field trials were executed on a three well pad in the Permian basin (PB). For the first 30 days oil and gas production appeared to be significantly higher than the average production from offset wells in the same area that were previously fractured with the same surfactant.
Sharma, Himanshu (The University of Texas at Austin) | Lu, Jun (The University of Texas at Austin) | Weerasooriya, Upali P. (The University of Texas at Austin) | Pope, Gary A. (The University of Texas at Austin) | Mohanty, Kishore K. (The University of Texas at Austin)
Recent studies on the use of ammonia as an alkali for performing alkali-surfactant-polymer (ASP) floods have shed light on its advantages over conventional alkalis such as lower alkali requirements, ease of transportation and storage. This study is aimed towards understanding surfactant adsorption in sandstone and carbonate rocks in the presence of ammonia. Zeta potential measurements were performed to characterize Bandera brown sandstone and Silurian dolomite surfaces in the presence of ammonia and sodium carbonate. A series of experiments were performed with and without ammonia such as static surfactant adsorption experiments on crushed Bandera brown sandstone and Silurian dolomite rocks, single phase surfactant transport experiments in sandstone and carbonate cores, surfactant phase behavior to identify an ultra-low interfacial tension (IFT) surfactant formulation, and oil recovery coreflood experiments using these surfactant formulations. Zeta potential measurements showed a reduction in zeta potential of Bandera brown and Silurian dolomite by adding ammonia to increase the pH. Surfactant adsorption experiments showed that ammonia was able to reduce the adsorption on sandstones, but not much difference was observed for carbonates. The ultra-low IFT surfactant formulations developed with and without ammonia showed very similar phase behavior. High oil recoveries and very low surfactant retentions were observed in the oil recovery experiments performed in sandstones.
Rohilla, Neeraj (TIORCO, a Nalco Champion Company) | Ravikiran, Ravi (Stepan Company) | Carlisle, Charlie T. (Chemical Tracers Inc.) | Jones, Nick (University of Wyoming) | Davis, Marron B. (Sunshine Valley Petroleum Corporation) | Finch, Kenneth B. H. (TIORCO, a Nalco Champion Company)
Sandstone reservoirs containing significant amount of clays (30-40 wt%) with moderate permeability (20-50 mD) provide a unique challenge to surfactant based enhanced oil recovery (EOR) processes. A critical risk factor for these types of reservoirs is adsorption of surfactants due to greater surface area attributed to clays. Clays also have high cation exchange capacity (CEC) and can release significant amounts of di-valents that lead to increased retention of the surfactant. These factors could adversely affect the economics of a flood.
We present a case study where a robust formulation was designed and tested in lab/field for a reservoir located in Wyoming, USA and contains up to 35-40 wt% clays (predominately Kaolinite and Illite). The residual oil saturation is high (Sor=0.4) while the permeability of the formation is between 20-50 mD. The reservoir has been waterflooded historically with low salinity water which has led to formation permeability damage. Due to high levels of clays, adsorption of the surfactant on the rock surface was determined to be between 3-4 mg/g rock by static adsorption tests.
This publication demonstrates how the following challenges have been successfully addressed in the lab as well as in the field in the form of single well chemical tracer test (SWCTT).
Designed a robust alkaline-surfactant-polymer (ASP) formulation that showed ultra-low interfacial tension (IFT) values and aqueous solubility remains soluble in the aqueous solution over a broad range of salinity. Mitigated surfactant adsorption issues to make the cEOR solution economic. A sacrificial agent was identified that acted synergistically with alkali and also did not alter the optimum salinity of the formulation. Performed restored state core analysis using the available damaged core material. The main challenge being restoration of the coreplugs to current reservoir conditions for coreflood experiment without causing additional formation damage due to injection of low salinity formation brine. Designed a flood that utilized a pre-flush to provide a favorable salinity gradient and to inject sacrificial agent ahead of the surfactant front. Performed polymer screening to select right molecular weight of polymer so that the right balance of mobility control and injectivity in the reservoir can be obtained.
Designed a robust alkaline-surfactant-polymer (ASP) formulation that showed ultra-low interfacial tension (IFT) values and aqueous solubility remains soluble in the aqueous solution over a broad range of salinity.
Mitigated surfactant adsorption issues to make the cEOR solution economic. A sacrificial agent was identified that acted synergistically with alkali and also did not alter the optimum salinity of the formulation.
Performed restored state core analysis using the available damaged core material. The main challenge being restoration of the coreplugs to current reservoir conditions for coreflood experiment without causing additional formation damage due to injection of low salinity formation brine.
Designed a flood that utilized a pre-flush to provide a favorable salinity gradient and to inject sacrificial agent ahead of the surfactant front.
Performed polymer screening to select right molecular weight of polymer so that the right balance of mobility control and injectivity in the reservoir can be obtained.
This is the final installment in a series of three papers examining iron mineralogy and its effect on surfactant adsorption in reservoir and outcrop rock samples. The goal of these studies is to establish best practices for obtaining surfactant adsorption values representative of those in a reduced oil reservoir, despite performing experiments in an oxidizing laboratory atmosphere.
This article follows two others examining the abundance and form of iron in the reservoir and in core samples (Part I:
Surfactant retention is a leading uncertainty in economic forecasting of chemical EOR, in large part due to the order-of-magnitude effects of artifacts such as improper core preservation. The industry standard is to (a) limit atmospheric contact of cores to the extent feasible, and (b) when necessary, reduce oxidized cores using strong reducing agents such as sodium dithionite, along with buffering and chelating agents such as sodium bicarbonate and EDTA or sodium citrate. However few studies have been performed to determine whether such invasive treatments are necessary, or what unintended effects the use of such reactive chemicals may have.
The most striking conclusion from these studies is the lack of clear evidence of any advantage of electrochemical reduction versus a simpler treatment with chelators such as sodium citrate or EDTA.
While treatment with a citrate-bicarbonate-dithionite solution does indeed lower adsorption several-fold further, solutions of either sodium bicarbonate or EDTA are at least as effective, and sodium citrate is almost as effective. These non-reductive treatments remove small amounts (~0.1% – ~0.2% of rock mass) of Fe and Al, and fines are invariably apparent in treatment fluids, both of which suggest removal of small amounts of trivalent Fe/Al colloids.
While these results suggest that non-reductive means may be used to remove artifacts introduced by core oxidation, they come with an important caveat: even rinsing with a brine solution can result in significant alteration of mineralogy. The use of chelating agents will invariably result in dissolution of any soluble minerals present such as gypsum or anhydrite, which can be an important contributor to surfactant (in particular ABS) consumption.
In cases where iron removal is necessary due to polymer degradation issues, PIPES buffer is proposed for use as an alternative to bicarbonate, the latter having a greater tendency for ligand formation. The combination of borohydride and bisulfite is suggested as an alternative to dithionite as a reducing agent, resulting in more complete iron removal under some conditions, and anecdotally less tendency for polymer degradation upon subsequent oxidation, though both of these claims should be verified.