Fracturing fluids are commonly formulated with fresh water to ensure reliable rheology. However, fresh water is becoming more costly, and in some areas, it is difficult to obtain. Therefore, using produced water in hydraulic fracturing has received increased attention in the last few years. A major challenge, however, is its high total dissolved solids (TDS) content, which could cause formation damage and negatively affect fracturing fluid rheology. The objective of this study is to investigate the feasibility of using produced water to formulate crosslinked-gel-based fracturing fluid. This paper focuses on the compatibility of water with the fracturing fluid system and the effect of salts on the fluid rheology.
Produced water samples were analyzed to determine different ion concentrations. Solutions of synthetic water with different amounts of salts were prepared. The fracturing fluid system consisted of natural guar polymer, borate-based crosslinker, biocide, surfactant, clay controller, scale inhibitor, and pH buffer. Compatibility tests of the fluid system were conducted at different cation concentrations. Apparent viscosity of the fracturing fluid was measured using a high-pressure high-temperature rotational rheometer. All rheology tests were conducted at a temperature of 180°F and were conducted according to API 13m procedure with a three-hour test duration. Fluid breaking test was also performed to ensure high fracture and proppant pack conductivity.
Produced water analysis showed a TDS content of 125,000 ppm, including Na, Ca, K, and Mg ion concentrations of 36,000, 10,500, 1,700, and 700 ppm, respectively. Results indicated the potential of produced water to cause formation damage. Therefore, produced water was diluted with fresh water and directly used to formulate the fracturing fluid. Divalent cations were found to be the main source of precipitation, and the reduced amounts of each ion were determined to prevent precipitation. The separate and combined effects of Na, K, Ca, and Mg ions on the viscosity of the fracturing fluid were also studied. Fluid viscosity was found to be significantly affected by the concentrations of divalent cations regardless of the concentrations of monovalent cations. Monovalent cations reduced the viscosity of fracturing fluid only in the absence of divalent cations, and showed no effect in the presence of Ca and Mg ions. Water with reduced concentrations of monovalent and divalent cations showed the most suitable environment for polymer hydration and crosslinking.
This paper contributes to the understanding of the main factors that enable the use of produced water for hydraulic fracturing operations. Maximizing the use of produced water could reduce its disposal costs, mitigate environmental impacts, and solve fresh water acquisition challenges.
Preliminary studies have been done to characterize rock-fluid properties, and flow mechanisms in the shale reservoirs. Most of these studies, through modifying methods used for conventional reservoirs, fail to capture dynamic features of shale rock and fluids in confined nano-pore space. In unconventional reservoirs, interactions between the wall of shale and the contained fluid significantly affect phase and flow behaviors. The inability to model capillarity with the consideration of pore size distribution characteristics using commercial software may lead to an inaccurate oil production performance in Bakken. This paper presents a novel formulation that consistently evaluates capillary force and adsorption using pore size distribution (PSD) directly from core measurements. The new findings could better address differences in flow mechanisms in unconventional reservoirs, and thus lead to an optimized IOR practice.
Wang, D. (University of North Dakota) | Dawson, M. (Statoil Gulf Services LLC) | Butler, R. (University of North Dakota) | Li, H. (Statoil Gulf Services LLC) | Zhang, J. (University of North Dakota) | Olatunji, K. (University of North Dakota)
With the recent dramatic drop in oil price, production from ultra-tight resources, like the Bakken formation, may drop substantially. Since expenditures for drilling, completion, and fracking have already been made, existing wells will continue to flow, but oil rates will decline—rapidly in many cases. In a low oil-price environment, what can be done to sustain oil production from these tight formations?
We are testing a surfactant imbibition process to recovery oil from shales. We measured surfactant imbibition rates and oil recovery values in laboratory cores from the Bakken shale. After optimizing surfactant formulations at reservoir conditions, we observed oil recovery values up to 10–20% OOIP incremental over brine imbibition. However, whether or not surfactant imbibition will be a viable recovery process depends on achieving sufficiently high oil production rates in a field setting—which requires that we identify conditions that will maximize imbibition rate, as well as total oil recovery. In this paper, we describe laboratory evaluations of oil recovery using different core plugs. These recovery studies involved
(1) surfactant formulation optimization on concentration, salinity and pH, (2) characterization of phase behavior, (3) spontaneous imbibition, and (4) forced imbibition (flooding) with gravity drainage assistance.
In preserved cores, we observed: (1) Formulations using 0.1% surfactant concentration at 4% TDS salinity showed favorable oil recoveries (up to 40% OOIP). (2) Generally, surfactant formulations at optimal concentration and salinity were stable at high temperature (115°C). (3) Injectivity/permeability enhancements up to 75 percent occurred after acidification using acetic acid or HCl. (4) Wettability alteration is the dominant mechanism for surfactant imbibition. Of course, actions that increase fracture width will aid gravity drainage and oil recovery. This information is being used to design and implement a field application of the surfactant imbibition process in an ultra-tight resource.
The application of surfactants to improve oil recovery in conventional reservoirs via wettability alteration and enhancement of spontaneous imbibition has been extensively studied in the literature. However, little work has been performed yet to investigate the interaction of these surfactants with ultra-tight oil-rich shale reservoirs such as Wolfcamp shale. The use of horizontal drilling and massive multistage hydraulic fracturing has made primary oil recovery from these ultra-tight oil-rich shale reservoirs possible. With declining production from existing shale wells, it is essential to explore potential "beyond primary" strategies in shale oil development. This paper analyzes the potential of surfactants in altering wettability and improving the process of spontaneous imbibition in oil rich shales demonstrating nanodarcy range permeability, relevant to stimulation and "beyond primary" chemical EOR applications in shales.
Novel proprietary surfactant blends along with traditional nonionic surfactants were investigated in this study using Wolfcamp shale core samples exhibiting nanodarcy permeability. X-ray diffraction analysis was performed which indicated that Wolfcamp shale has mixed mineralogy, with quartz, calcite, and dolomite acting as the major minerals in varying proportions depending on the interval depth. Contact angle and interfacial tension measurements were performed at reservoir temperature to identify the state of native wettability and the impact of surfactants in altering wettability. Thereafter, spontaneous imbibition experiments were performed using 3D computed tomography methods to understand the improvement in the magnitude of imbibition penetration due to surfactant addition. Contact angle and spontaneous imbibition experiments showed that Wolfcamp shale is intermediate-wet and surfactants have the potential to alter the native wettability to a preferentially water-wet state and improve oil recovery due to enhanced spontaneous imbibition.
Surfactants which altered the wettability significantly, but lowered the interfacial tension only slightly showed the highest oil recoveries due to the creation of strong capillary driven forces directly responsible for effective spontaneous imbibition. The potential of surfactants in altering wettability and improving oil recovery via enhanced spontaneous imbibition in ultra-tight oil-rich shales was verified in this study. The effectiveness of traditional nonionic surfactants in altering wettability and improving oil recovery was found to be comparable to that of novel, more expensive proprietary surfactant blends, and hence, the traditional nonionic surfactants provide a cost effective option for stimulation and EOR applications in Wolfcamp shale. Overall, this paper presents the theory behind surfactant interaction with ultra-tight shales and provides experimental results to validate the viability of surfactant induced improved oil recovery in shales.
Improved Oil Reocvery (IOR) technologies may offer a new strategy to improve the initial production (IP) and slow the production decline from oil-rich shale formations. Early implementation of chemical IOR technologies largely have been overlooked during strategic planning of unconventional reservoirs. The purpose of this study is to improve understanding of the dynamic processes of oil displacement by surfactants and to investigate mechanism of how surfactants extract oil. A successful conventional surfactant "huff-n-puff' treatment is described with a focus on any relationship between increased oil production and the surfactant soaking period. Surfactant chemistry has been considered as one of a few ultimate IOR solutions. Despite being well proven as effective chemicals to recover oil from convenetional reservoris, surfactants commonly are used in hydraulic fracturing of unconventional reservoris are just to promote flow back of the injected aqueous fluid over a relatively short time frame. In order to better understand the functionality of surfactants for obtaining favorable oil interaction with both the stimulation fluid and rock matrix, a specifically-designed "oil-on-a-plate" (OOAP) setup and procedure is employed to examine the penetration of surfactant into the oil-film that is adhereing to a solid surface. In addition to the well-recognized spontaneous imbibition and surface wettability alternation processes, surfactant also can gradually penetrate and mobilize oil droplets, resulting in improved oil recovert. If properly selected and designed, the surfactant additives in stimulation/fracturing fluids could have multi-functions towards improving both IP and the longer-term oil production. Besides serving as a demulsifier and flowback enhancer to boost IP, the surfactants could continuously lift-up and mobilize adsorbed oil to increase recoverable oil in place.
As one of the unconventional resources, tight oil has become one of the most important contributor of oil reserves and production growth. The successful commercial production of tight oil is mainly reliant on the advancement in horizontal drilling and multistage hydraulic fracturing technique. Development of tight oil reservoirs remains in an early stage. Primary oil recovery factor in these reservoirs is very low, leaving substantial volume of oil trapped underground due to the low porosity, low permeability characteristic of tight oil reservoirs. Thus, investigation of enhanced oil recovery methods is more than imperative in tight oil reservoirs. CO2 Huff-and-Puff technology has been effectively applied in conventional reservoirs and can be tailored to adapt for the characteristics of tight oil reservoirs.
In this study, the performance of water flooding in tight oil reservoir is studied and compared with that of the CO2 Huff-and-Puff process. Sensitivity analysis demonstrates that the performance of CO2 Huff-and-Puff is more sensitive to the length of gas injection and production step in each cycle, compared to the soaking time. The CO2 Huff-and-Puff process is optimized and an adaptive CO2 Huff-and-Puff process is conducted for tight oil reservoirs after primary production. Simulation results show that the adaptive cycle length CO2 Huff-and-Puff process can improve the incremental oil recovery by 11.1% over a fixed cycle length process. Finally, the inter-well interference during CO2 Huff-and-Puff is studied, and it is found that a multi-well asynchronous CO2 Huff-and-Puff pattern can improve the incremental oil recovery by 31.6% over that of a synchronous pattern.
Fracture treatment performance in Bakken shale reservoirs can be improved by altering rock wettability, as measured with contact angle (CA), from oil-wet to water-wet. The use of chemical additives for altering wettability also results in alteration of the interfacial tension (IFT). The Young-Laplace equation relates the capillary pressure to IFT and contact angle. Thus, it follows that capillarity is significant in nano-pores associated with unconventional liquid reservoirs (ULR) and complex as the CA and IFT varies simultaneously. We carefully evaluate these interactive variables to improve oil recovery by alteration of capillary pressure by understanding the wetting state of siliceous and carbonate Bakken cores with and without chemical additives. We have observed that wettability can be altered from the ULR natural state of oil-wet to systems favoring frac fluid imbibition. Surfactants can be added to completion fluids, in proper concentrations, to alter wettability while hydraulic fracturing the formation. This experimental study evaluates and compares the efficiency of anionic, nonionic and blended surfactants as well as complex nanofluids (CNF) on recovering liquid hydrocarbons from Bakken shale cores by analyzing the effect of wettability and IFT alteration and their impact on spontaneous imbibition.
The original wettability of Bakken cores is determined by CA measurements. Then, three surfactant types, anionic nonionic and nonionic-cationic, and CNF are evaluated to gauge their effectiveness in altering wettability. The results show that all surfactants and CNF are able to shift core wettability from oil-wet to water-wet. However, chemical additives efficacy strongly depends on rock lithology, surfactant, and CNF type. Moreover, to evaluate further wettability alteration, stability of surfactant and CNF solution films on the shale rock surface is determined by zeta potential measurements. Surfactants and CNF show higher zeta potential magnitudes than water without additives, as an indication of better stability and water-wetness, which agrees with CA results. In addition, the effect of IFT alteration is studied in solutions with surfactants and CNF, and Bakken crude oil. Higher IFT reduction is achieved by anionic surfactants, but all surfactants and CNF perform better than water alone.
Surfactants and CNF potential for improving oil recovery in ultralow permeability Bakken cores is investigated by spontaneous imbibition experiments using modified Amott cells in an environmental chamber. Using computed tomography (CT) scan methods, water imbibition as penetration magnitude is measured in real time. In addition, oil recovery is recorded with time to compare the performance of surfactants, CNF, and completion fluid alone. The results suggest that surfactants and CNF are better on recovering oil from shale core displacing more oil and having higher penetration magnitudes than water without additives. In addition, oil recovery depends on surfactant and CNF type and rock mineral composition. These findings are consistent with CA, zeta potential, and IFT measurements. From the results obtained, it can be concluded that altering wettability and reducing IFT when surfactants and CNF additives are added to completion fluids can improve oil recovery in Bakken cores.
Compositional reservoir simulation plays a vital role in the development of conventional and unconventional reservoirs. Two major building blocks of compositional simulation are phase behavior and fluid transport computations. The oil and gas reserves and flow of reservoir fluids are strongly dependent on phase behavior. In conventional reservoirs, capillary pressure is relatively small and is typically ignored in phase behavior calculations. However, large capillary pressure values are encountered in tight formations such as shales; and therefore, its effects should not be ignored in phase equilibria calculations. Neglecting the effects of capillary pressure on phase behavior can lead to an inaccurate estimation of original oil and gas in place as well as recovery performance. In spite of this, the effect of capillary pressure on phase behavior in tight reservoirs has not been well studied using compositional simulation, especially for hydraulically-fractured reservoirs.
In this paper, we develop a new compositional reservoir simulator capable of modeling discrete fractures and incorporating the effect of capillary pressure on phase behavior. Large-scale natural and hydraulic fractures in tight rocks and shales are modeled with a technique called Embedded Discrete Fracture Model (EDFM) where fractures are modeled explicitly without using local grid refinement or an unstructured grid. Flow of hydrocarbons occurs simultaneously within similar and different porosity types. Capillary pressure is considered in both flow and flash calculations, where simulations also include variable pore size as a function of gas saturation in each grid block. We examine the impact of capillary pressure on the original oil in place and cumulative oil production for different initial reservoir pressures (above and below the bubble-point pressure) on Bakken and Eagle Ford fluids. The importance of capillary pressure on both flow and flash calculations from hydraulically fractured horizontal wells during primary depletion in fractured tight reservoirs using Bakken fluid composition is demonstrated.
Phase behavior calculations show that bubble-point pressure is suppressed allowing the production to remain in the single-phase region for a longer period of time and altering phase compositions and fluid properties such as density and viscosity of equilibrium liquid and vapor. The results show that bubble-point suppression is larger in the Eagle Ford shale than for Bakken. When capillary pressure is considered, we found an increase in original oil in place up to 4.1% for Bakken and 46.33% for the Eagle Ford crude. Depending on the initial reservoir pressure, cumulative primary production after one year increases owing to capillary pressure by approximately 9.0 – 38.2% for Bakken oil and 7.2 – 154% for Eagle Ford oil. The recovery increase caused by capillary pressure becomes more significant when reservoir pressure is far below bubble-point pressure. The simulation results with hydraulically fractured wells give similar recovery differences; cumulative oil production after 1 year is 3.5 – 5.2% greater when capillary pressure is considered in phase behavior calculations for Bakken.
Production from tight formation resources leads the growth in U.S. crude oil production. Compared with chemical flooding and water flooding, gas injection is a promising EOR approach in shale reservoirs. A limited number of experimental studies concerning gas flooding in the literature focus on unconventional plays. This study is a laboratory investigation of gas flooding to recover light crude oil from nano-permeable shale reservoirs.
In this work, the N2 flooding process was applied to Eagle Ford core plugs saturated with dead oil. To investigate the effects of flooding time and injection pressure on the recovery factor, two groups of core-flood tests were performed. In group one, flooding time ranged from 1 to 5 days in increments of 1 day; in the other group, the injection pressure ranged from 1,000 psi to 5,000 psi in increments of 1,000 psi. The experimental setup was monitored using X-ray CT that helped to visualize phase flow and estimate the recovery efficiency during the test.
The potential of N2 flooding for improving oil recovery from shale core plugs was examined, and the recovery factor (RF) of each case was presented. The results from group one showed that more oil was produced with a longer flooding time. However, the incremental RF decreased with the increase of flooding time. The oil recovery was significant at the initial period of the recovery process, and a longer flooding time had less effect on extracting more oil. With flooding time constant in 1-day, the results from the second group indicated that RF increased with injection pressure, especially rising pressure, from 1,000 psi to 2,000 psi. The gas breakthrough time became shorter with the increase of injection pressure. The analysis of the CT number showed that the oil recovery process mainly occurred before the gas breakthrough. Once a fluid flow path was established, the injected gas flowed through the limited communication channels; thus, no extra oil could be extracted without increasing the injection pressure. This experimental study illustrates that gas flooding has liquid oil production potential in shale reservoirs.
Liang, Tianbo (The University of Texas at Austin) | Achour, Sofiane H. (The University of Texas at Austin) | Longoria, Rafael A. (The University of Texas at Austin) | DiCarlo, David A. (The University of Texas at Austin) | Nguyen, Quoc P. (The University of Texas at Austin)
Significant amount of fracturing fluid is lost after hydraulic fracturing, and it is believed that the loss of fluid into the matrix can hinder the hydrocarbon production. One way to reduce this damage is to use the surfactants. Robust surfactant formulations have been developed for chemical enhanced oil recovery (CEOR); similar ideas are introduced in this study to reduce water blocks in low permeability reservoirs. Here we present an experimental investigation based on a coreflood sequence that simulates fluid invasion, flowback, and hydrocarbon production within the rock near the fracture face. Different levels of IFT reductions are tested and compared in order to explore the best condition that maximizes the permeability enhancement. The effect of in-situ microemulsion generation to mobilize the trapped water is also studied. From this work, we recognize the mechanism responsible for the permeability damage in matrix and we suggest criteria to optimize the performance of surfactant additives so as to enhance the hydrocarbon production from low permeability gas/oil reservoirs after hydraulic fracturing.