Lu, Jun (University of Texas At Austin) | Goudarzi, Ali (University of Texas At Austin) | Chen, Peila (University of Texas At Austin) | Kim, Do Hoon (University of Texas At Austin) | Britton, Christopher (University of Texas At Austin) | Delshad, Mojdeh (University of Texas At Austin) | Mohanty, Kishore K. (University of Texas At Austin) | Weerasooriya, Upali Peter | Pope, Gary Arnold
Large volumes of oil remain in naturally fractured carbonate oil reservoirs and water floods are often very inefficient because many of these reservoirs are mixed-wet or oil-wet as well as extremely heterogeneous. Naturally fractured reservoirs are
challenging targets for chemical flooding because they typically have a high permeability contrast between the fractures and the matrix with low to extremely low matrix permeability. In addition, some of the world's largest oil reservoirs are fractured
carbonates with high reservoir temperature and high salinity formation brine and some of them also have low API gravity oils, which also increases the difficulty of recovering the oil. We have developed a stable surfactant that shows promising
results even when all of these conditions are present at the same time. Both static and dynamic imbibition experiments were done using a fractured carbonate core. These results were interpreted using a mechanistic chemical reservoir simulator.
Roshanfekr, Meghdad (University of Texas at Austin) | Johns, Russell T. (Pennsylvania State University at University Park) | Pope, Gary (University of Texas at Austin) | Britton, Larry (University of Texas at Austin) | Linnemeyer, Harold (University of Texas at Austin) | Britton, Christopher (University of Texas at Austin) | Vyssotski, Alexander (University of Texas at Austin)
Surfactant/polymer (SP) and alkali/surfactant/polymer flooding is of current interest because of the need to recover residual oil after primary and secondary recovery. If designed properly, these enhanced-oil-recovery processes can give very high oil recoveries. Microemulsion phase behavior plays a central role in process performance and is typically measured by performing salinity scans in glass pipettes at atmospheric pressure and reservoir temperature using dead crude oil from the reservoir of interest. There have been only a few experiments reported in the literature on live oil at reservoir pressure and temperature, and the importance of those experimental results is conflicting.
This paper investigates the effect of pressure and solution gas on microemulsion phase behavior and its impact on oil recovery. We examine previous data reported in the literature, and report new measurements with live oil to show that the optimum parameters can change significantly. The experiments show that while pressure induces a phase transition from upper microemulsion (Winsor Type II+) to lower microemulsion (Winsor Type II?), solution gas does the opposite. An increase in pressure decreases the optimum solubilization ratio and shifts the optimum salinity to a larger value. Adding methane to dead oil at constant pressure does the reverse. Thus, these effects are coupled and both must be taken into account. Using a numerical simulator, we show that these changes in the optimum conditions can significantly impact oil recovery if not accounted for in the SP design.
Sharma, Abhinav (Rex Energy Corporation) | Azizi, Alex (REX ENERGY) | Clayton, Bryan James (Rex Energy Operating Corp) | Baker, Greg (Rex Energy) | Mckinney, Patrick Michael (Rex Energy) | Britton, Christopher (U Of Texas At Austin) | Delshad, Mojdeh (U. of Texas at Austin) | Pope, Gary Arnold (U. of Texas at Austin)
A tertiary Alkaline-Surfactant-Polymer pilot flood was implemented during 2010 in the Illinois Basin of the United States and is continuing at this time. With initial discovery of the Bridgeport Sandstone formation in the early 1900's and over 60 years of waterflooding, the pilot was designed to demonstrate that ASP flooding could produce significant quantities of incremental oil in order to sanction a commercial project. Laboratory experiments including corefloods were done to determine the optimal chemical formulation for the pilot and to provide essential parameters for a numerical simulation model. Polymer injectivity tests, single well chemical tracer tests and an interwell tracer test program were all done to prepare for and support a full interpretation of the pilot results. A field laboratory was run through the duration of the pilot to monitor the quality the injection and production fluids, which turned out to be critical to the success of the pilot. We present the results and interpretation of the ASP pilot to date, the challenges faced during the project, and the lessons learnt from the field perspective.
Surfactant retention is one of the most important variables affecting the economics of chemical flooding and varies widely depending on the surfactant structure, mineralogy, salinity, pH, Eh, microemulsion viscosity, crude oil, co-solvent and mobility control among other variables. We have done a large number of dynamic surfactant retention measurements over a wide range of conditions using a variety of new-generation surfactants to recover crude oils from both sandstone and
carbonate cores. Surfactant retention values for both surfactant-polymer (SP) and alkaline-surfactant-polymer (ASP) floods were measured and correlated with pH, total acid number (TAN) of the oil, temperature, co-solvent concentration, salinity of the polymer drive, mobility ratio, and molecular weight of the surfactant. Surfactant retention values ranged from about 0.01 to 0.37 mg/g of rock. SP and ASP formulations included mixtures of anionic and nonionic surfactants with and without cosolvents. The retention of anionic surfactants of all types was found to be similar on both sandstones and carbonate rocks.
The mechanism of surfactant retention is complicated and it depends on several factors such as surfactant structure, mineralogy, salinity, clay content, pH, Eh, microemulsion viscosity, crude oil, co-solvent and mobility control among other variables. A few of the vast number of papers written on surfactant adsorption are briefly reviewed below.
Effect of Surfactant Type and pH. It is well known that surfactant structure affects adsorption on rock surfaces. Traditionally, anionic surfactants were not considered for carbonates because of concerns about high adsorption. However, increasing the pH greatly reduces the adsorption of anionic surfactants on carbonate surfaces. Zhang et al. (2006) observed that using sodium carbonate as an alkali reverses the charge of the calcite surface from positive to negative, leading to less adsorption of anionic surfactants. Interestingly, the same was not observed when sodium hydroxide was used as an alkali.
They proposed that the reason could be the carbonate is a potential determining ion (for carbonate surfaces) whereas a hydroxide is not. However, alkali cannot be used in all cases, so in such cases the most effective SP formulation without alkali must be developed and evaluated. Some anionic surfactants have shown low surfactant retention in carbonates even without alkali that are comparable to the retention in sandstones at typical reservoir pH values. This surprise finding implies that the surfactant retention due to phase trapping and unfavorable phase behavior contributes as much or more than the
Effect of Clay Content. For sandstones, surfactant adsorption depends more on the clay surfaces than on the quartz surface. Silica is negatively charged at reservoir conditions and exhibits negligible adsorption of anionic surfactants at high pH (Hirasaki et al., 2008). At neutral pH, clays have a negative charge on the faces and a positive charge at the edges. The edges exhibit pH dependent charge characteristics, and thus are expected to reverse their charge at a pH of about 9 (Somasundaran and Hanna, 1977; Hirasaki et al., 2008; Sheng, 2011). Wang (1993) also observed similar behavior and concluded that surfactant adsorption on Loudon and Berea sandstones results primarily from the presence of clays. He also showed that preserving the core in reduced conditions (by dithionite treatment) significantly reduced the surfactant adsorption.
Solairaj, Sriram (U Of Texas At Austin) | Britton, Christopher (U Of Texas At Austin) | Lu, Jun (University Of Texas At Austin) | Kim, Do Hoon (U. of Texas at Austin) | Weerasooriya, Upali (U. of Texas at Austin) | Pope, Gary Arnold (U. of Texas at Austin)
It is well known that the oil recovery efficiency of chemical EOR depends on microemulsion phase behavior and interfacial tension (IFT). The surfactants needed to obtain good phase behavior and ultra-low IFT vary greatly with oil characteristics and reservoir conditions. Hence, it is often necessary to test many surfactant formulations before finding a highly effective one. Based on both sound principles and extensive experience, one would expect to find a relationship between the optimum surfactant structure, the oil characteristics, the brine, and the temperature. Salager's equation (Salager et al., 1979, Anton et al., 2008) shows it is possible to correlate some of these variables to classical surfactant structure. We now have many new surfactants with widely different structures and many more good formulations with a wider range of oils, temperature and so forth. Thus, it becomes imperative to study the underlying trend and to identify the most important variables affecting the optimum surfactant structure. A new correlation has been developed using an extensive data set taking into account the effect of propylene oxide number (PON), ethylene oxide number (EON), temperature, brine salinity and the equivalent alkane carbon number (EACN) of the oil. The new correlation will help in identifying the most important variables and also to improve our understanding of the relationship among variables affecting optimum surfactant structure. In particular, the new equation can be used to predict the optimum carbon number of the surfactant hydrophobe. Results show that larger hydrophobes are needed as either the temperature or the equivalent alkane carbon number (EACN) of the oil increases. The surfactant formulations used for this study include mixtures of sulfate, sulfonate, carboxylate and non-ionic surfactants. This is a new and highly significant advance in the optimization of chemical EOR processes that will greatly reduce the time and cost of the effort required to develop a good formulation as well as to improve its performance.
Griffin (1949) first introduced the concept of hydrophilic-lipophilic balance (HLB) to quantify for the relative affinity of surfactant for water and oil. According to this empirical relation, each oil is characterized by "required HLB?? (HLBreq), corresponding to the HLB of the surfactant resulting in the most stable emulsion. However, this method doesn't take into account the effect of other formulation variables such as salinity, hardness, temperature, alkali, alcohol (co-solvent) type and concentration and co-surfactant type and concentration. Winsor (1954) introduced the R-ratio that relates the relative energies of interaction between the surfactant adsorbed at the interface and the aqueous and oil phases surrounding it. It takes into account the molecular effects at the interface, but is still limited by the fact that energies of interaction cannot be measured experimentally. Shinoda (1964) proposed a method based on the determination of phase inversion temperature (PIT) - equivalent to cloud point phenomenon (decrease in hydrophilicity of ethylene oxide moiety of surfactants upon heating). It takes into account the effect of formulation variables (salinity, oil, additives), but in practice this technique can be applied only to ethoxylated nonionic surfactants, since ionic surfactants show opposite sensitivity to temperature.