Calcium sulfate scale precipitation is a challenge especially during stimulation treatments. The main objective of this study is to mitigate calcium sulfate precipitation during fracturing treatment. With high sulfate content in source/mixing water up to 2,000 parts per million (ppm) and excessive of total dissolved solids (TDS) formation water that can reach 60,000 ppm calcium.
An experimental study was conducted at the reservoir downhole temperature of 280°F to evaluate the formation water compatibility with source water wells used for fracturing fluids. The sulfate content varied in the fracturing fluids up to 2,000 ppm. This paper addresses: the scaling tendency of water-water interaction; the efficiency and minimum inhobitor concentration of three commercial calcium sulfate scale inhibitors; the stability of high sulfate fracturing fluids at 280°F (138°C) with scale inhibitors.
This study indicated: water-water compatibility tests reinforce the mineral risk assessments findings for calcium sulfate scales, scale inhibitors were effective to prevent scale deposition when added at 1.5 gpt to the source water. The high pH-fracturing gelled fluids must be prepared using relatively low sulfate water (SO42- ≤ 500 ppm). The scale inhibitors, when added to the high pH-fracturing, gelled fluids at minimum inhibit concertation will not negatively affect the polymer gel rheology and adhesion.
The study set guidelines to prevent calcium sulfate scales issues during fracturing jobs with incompatible source and extreme salinities formation water. The lesson learned exhibits an effective practice to maximize treatment efficiency and minimize formation damage that could be induced during fracturing.
Rognmo, Arthur U. (University of Bergen) | Al-Khayyat, Noor (University of Bergen) | Heldal, Sandra (University of Bergen) | Vikingstad, Ida (University of Bergen) | Eide, Øyvind (University of Bergen) | Fredriksen, Sunniva B. (University of Bergen) | Alcorn, Zachary P. (University of Bergen) | Graue, Arne (University of Bergen) | Bryant, Steven L. (University of Calgary) | Kovscek, Anthony R. (Stanford University) | Fernø, Martin A. (University of Bergen)
The use of nanoparticles for CO2-foam mobility is an upcoming technology for carbon capture, utilization, and storage (CCUS) in mature fields. Silane-modified hydrophilic silica nanoparticles enhance the thermodynamic stability of CO2 foam at elevated temperatures and salinities and in the presence of oil. The aqueous nanofluid mixes with CO2 in the porous media to generate CO2 foam for enhanced oil recovery (EOR) by improving sweep efficiency, resulting in reduced carbon footprint from oil production by the geological storage of anthropogenic CO2. Our objective was to investigate the stability of commercially available silica nanoparticles for a range of temperatures and brine salinities to determine if nanoparticles can be used in CO2-foam injections for EOR and underground CO2 storage in high-temperature reservoirs with high brine salinities. The experimental results demonstrated that surface-modified nanoparticles are stable and able to generate CO2 foam at elevated temperatures (60 to 120°C) and extreme brine salinities (20 wt% NaCl). We find that (1) nanofluids remain stable at extreme salinities (up to 25 wt% total dissolved solids) with the presence of both monovalent (NaCl) and divalent (CaCl2) ions; (2) both pressure gradient and incremental oil recovery during tertiary CO2-foam injections were 2 to 4 times higher with nanoparticles compared with no-foaming agent; and (3) CO2 stored during CCUS with nanoparticle-stabilized CO2 foam increased by more than 300% compared with coinjections without nanoparticles.
Application of horizontal wells and multi-stage fracturing has enabled oil recovery from extremely low permeability shale oil reservoirs, but the decline in production rate is more than two thirds in the first two years. We are trying to develop chemicals that can be injected into old wells to stimulate oil production before putting the well back in production. The goal of this work is to evaluate chemical blends for such a process at the laboratory scale. The chemical blend contains surfactants, a weak acid, a potential determining ion, and a solvent. Six different solvents were screened: Cyclohexane, D-Limonene, Dodecane, Kerosene, Turpentine, and Green Solvent®. Most of the chemical blends with the solvents extracted about 60% of the oil from shale chips, but the Green Solvent® extracted about 84%. Spontaneous imbibition tests were performed with outcrop Mancos shale cores. Oil was injected into these outcrop cores at a high pressure. NMR T2 distributions were measured for the cores in the original dry state, after oil injection and after imbibition. The aqueous phase from the chemical blend imbibed into the cores and pushed out a part of the oil and gas present in the cores. The surfactant in these blends can change wettability and interfacial tension. The solvent can mix with the oil and solubilize organic solid residues such as asphaltenes. The weak acid can dissolve a part of the carbonate minerals and improve permeability. The synergy can make these chemical blends strong candidates to stimulate oil recovery in shale formations.
This paper demonstrates how 280ft of oil column spread unevenly across multiple and differentially depleted reservoir units separated by shale layers of varying thicknesses in a highly deviated (62 deg.) well was perforated in a one trip system and how the project cost was minimized by achieving multiple perforations in a single trip whilst retaining capacity to effectively cure losses and mitigating post-perforation well control risks. Against the conventional perforation methodology where reservoir units are perforated individually, isolated before carrying out the next perforation in the subsequent reservoir. The one trip system was designed and deployed in one run targeting all the 6 separate carefully selected sand lobes in one run ensuring good standoff from the contact and zonal isolation behind casing. Successful execution was confirmed with all the expected physical outcomes which includes pipe vibration, brine loss as well as inspection of the spent guns. A post perforation noise and production logging also confirmed flow across all planned perforation intervals. Perforation of a highly deviated well in differentially depleted multi-lobed reservoirs present significant operational risks. This paper illustrates how one can safely collapse multiple conventional perforation runs into a single trip with its attendant benefits on cost efficiency, crossflow and well control. This is the first of its kind in the Niger Delta.
We provide experimental evidence of wettability alteration using seawater salinity brine of an oil-wet system composed of a three-dimensional carbonate micromodel, crude oil, and connate-water brine salinity. We designed this procedure as a first step for evaluation of using seawater as an Improved Oil Recovery (IOR) agent. Our innovative design combines two main experimental best practices: micromodels, for repeatable experiments and X-ray computed tomography (CT) as a non-invasive technique for monitoring in situ fluid distribution. Both practices merge into a new three-dimensional micromodel set-up that uses only reservoir species (no high x-ray contrast chemicals).
Wettability alteration plays a key role to improve oil recovery from matrix blocks surrounded by water-invaded fractures in carbonate reservoir rocks. We designed a simple and replicable experimental apparatus and procedure to quantify contact angle distributions inside of porous media with a controlled level of heterogeneity in roughness and mineralogy. This experiment consists of visualizing the in-situ contact angle distribution of the aqueous phase inside a three-dimensional carbonate micromodel. Using Micro Computerized Tomography (MicroCT), we obtained three-dimensional images of fluid distribution with a voxel size of 3.8 microns.
We successfully studied the wettability state after connate water displacement and we also altered wettability of the carbonate porous medium from more oil wet to less water wet conditions. The water contact angle of the ganglia showed a 70% reduction in contact angle from an oil-wet to a water-wet system using an approximate seawater salinity and a 63% reduction in contact angle in the case of a full synthetic seawater. The initial average contact angles were 140° and 142° for the two solutions, respectively. After EOR seawater flooding, the average contact angle declined to 44° and 51°, respectively.
Ba Geri, Mohammed (Missouri University of Science and Technology) | Ellafi, Abdulaziz (University of North Dakota) | Flori, Ralph (Missouri University of Science and Technology) | Noles, Jerry (Coil Chem LLC) | Kim, Sangjoon (Coil Chem LLC)
Viscoelastic property of high-viscosity friction reducers (HVFRs) was developed as an alternative fracturing fluid system because of advantages such as the ability to transport particles, higher fracture conductivity, and potential lower cost due to fewer chemicals and equipment on location. However, concerns remain about using HVFRs to transport proppant in DI water and harsh brine solution (e.g. 2wt% KCl and 10 lbs. brine). The primary objective of this study is to investigate the viscoelastic property that can help to understand the true proppant transporting capacity of fracturing fluids in high-TDS environment.
To address the evaluation performance of HVFRs, a comprehensive review of numerous papers associated to viscoelastic property of hydraulic fracturing fluids were investigated and summarized. This paper also provides a full comparison study of viscosity and elastic modulus between HVFRs and among fracturing fluids such as xanthan, polyacrylamide-based emulsion polymer, and guar. Moreover, viscosity profiles and elastic modulus were conducted at different temperatures. Better proppant transportation effect though higher viscosity through Stoke's law and the effect on proppant transportation from elastic modulus comparison were also investigated. Finally, HVFR Conductivity test and successful field test result were explained.
The results of the experimental work show that viscoelastic property HVFRs provides good behavior to transport proppant. Viscosity profile decreased slightly as the temperature increased from 75 to 150 when the DI water was used. While using 10 lbs. Brine the viscosity was reduced by 33%. The longer polymer chains of HVFR indicated better elastic modulus in DI water. The elastic modulus also indicated that the highest values at frequency 4.5 Hz from each amplitude, and lower values as amplitude was increased. Although high molecular weight HVFRs were utilized on the conductivity test, the results observed that the regained permeability was up to 110%. Finally, the promising results from the case study showed that using HVFRs could be performed economically and efficiently for the purpose of proppant transportation and pressure reduction in high TDS fluids.
The goal of this work is to evaluate the applicability of a novel set of surfactants to enhance recovery from a viscous oil, high temperature, high permeability, clastic reservoir. A large number of novel short-hydrophobe based surfactants/cosolvents were designed and synthesized. As these surfactants do not require expensive aliphatic alcohols for their synthesis, they are likely to be less costly than conventional anionic surfactants. Here only phenol hydrophobe based non-ionic surfactants with varying number of propylene oxide (PO) and ethylene oxide (EO) groups are discussed. These surfactant molecules were investigated for their aqueous stability limits, interfacial tensions (IFT) with a viscous crude oil and oil recovery from sandpack or sandstone cores. Surfactant phase behavior experiments with viscous crude oil showed low IFT (not ultralow) for single surfactant systems. Only one surfactant (Phenol-7PO-15EO) formulation was chosen for coreflood in sandpack and sandstone cores. Water flood recovered about 50% original oil in place (OOIP) and reduced the oil saturation to about 48% in the high permeability sandpacks. The tertiary surfactant polymer flood with Phenol-7PO-15EO increased the cumulative recovery to 99% for sandpacks. The oil recovery was insensitive to injection brine salinity in the range studied. As the permeability decreased, the tertiary oil recovery decreased if the permeability is lower than 7 Darcy. Surfactant-polymer (SP) formulations with this surfactant can be recommended for high permeability sandstone reservoirs with viscous oils, but not for sub-Darcy sandstones.
Lara Orozco, Ricardo A. (The University of Texas at Austin) | Abeykoon, Gayan A. (The University of Texas at Austin) | Wang, Mingyuan (The University of Texas at Austin) | Argüelles Vivas, Francisco J. (The University of Texas at Austin) | Okuno, Ryosuke (The University of Texas at Austin) | Lake, Larry W. (The University of Texas at Austin) | Ayirala, Subhash C. (Saudi Aramco) | AlSofi, Abdulkareem M. (Saudi Aramco)
Reservoir wettability plays an important role in waterflooding especially in fractured carbonate reservoirs since oil recovery from the rock matrix is inefficient because of their mixed wettability. This paper presents the first investigation of amino acids as wettability modifiers that increase waterflooding oil recovery in carbonate reservoirs.
All experiments used a heavy-oil sample taken from a carbonate reservoir. Two amino acids were tested, glycine and β-alanine. Contact angle experiments with oil-aged calcite were performed at room temperature with deionized water, and then at 368 K with three saline solutions: 243,571-mg/L salinity formation brine (FB), 68,975-mg/L salinity injection brine 1 (IB1), and 6,898-mg/L salinity injection brine 2 (IB2). IB2 was made by dilution of IB1.
The contact angle experiment with 5-wt% glycine solution in FB (FB-Gly5) resulted in an average contact angle of 50°, in comparison to 130° with FB, at 368 K. Some of the oil droplets were completely detached from the calcite surface within a few days. In contrast, the β-alanine solutions were not effective in wettability alteration of oil-aged calcite with the brines tested at 368 K.
Glycine was further studied in spontaneous and forced imbibition experiments with oil-aged Indiana limestone cores at 368 K using IB2 and three solutions of 5 wt% glycine in FB, IB1, and IB2 (FB-Gly5, IB1-Gly5, and IB2-Gly5). The oil recovery factors from the imbibition experiments gave the Amott index to water as follows: 0.65 for FB-Gly5, 0.59 for IB1-Gly5, 0.61 for IB2-Gly5, and 0.33 for IB2. This indicates a clear, positive impact of glycine on wettability alteration of the Indiana limestone cores tested.
Two possible mechanisms were explained for glycine to enhance the spontaneous imbibition in oil-wet carbonate rocks. One mechanism is that the glycine solution weakens the interaction between polar oil components and positively-charged rock surfaces when the solution pH is between glycine's isoelectric point (pI) and the surface's point of zero charge (pzc). The other mechanism is that the addition of glycine tends to decrease the solution pH slightly, which in turn changes the carbonate wettability in brines to a less oil-wet state.
The amino acids tested in this research are non-toxic and commercially available at relatively low cost. The results suggest a new method of enhancing waterflooding, for which the novel mechanism of wettability alteration involves the interplay between amino acid pI, solution's pH, and rock's pzc.
In this paper the dielectric constant of shaly sands both the real and imaginary parts is investigated and compared. An empirical model has been developed in the one MHz to one GHz frequency range for the real part of the dielectric constant. The equations developed involve the same pore systems as those governing the conductivity response. The dielectric constant contains an additionalfrequency independent high frequency limit. The dispersive terms are due to the clays and interfacial phenomena. The salinity and frequency dependence of these parameters are then discussed.
This salinity dependence of the dielectric model is compared to the salinity dependence both predicted and measured for the conductivity. Conductive inclusions are modeled similar to previously published work (
Almeida da Costa, Alana (Universidade Federal da Bahia) | Jaeger, Philip (Eurotechnica GmbH) | Santos, Joao (Láctea Científica) | Soares, João (University of Alberta) | Trivedi, Japan (University of Alberta) | Embiruçu, Marcelo (Universidade Federal da Bahia) | Meyberg, Gloria (Universidade Federal da Bahia)
Low salinity waterflooding and CO2 injection are enhanced oil recovery (EOR) methods that are currently growing at a substantial rate worldwide. Linking these two EOR methods appears to be a promising approach in mature fields and for the exploration of post- and pre-salt basins in Brazil. Moreover, the latter reservoirs already have high CO2 content in the gas phase. Interfacial phenomena between fluids and rock in low salinity brine/CO2 environment still remain unclear, particularly the wettability behavior induced by the pH of the medium. In this study, coreflooding experiments, zeta potential, contact angle, interfacial tension (IFT), and pH measurements at ambient and reservoir conditions were performed to investigate the influence of the rock composition and brine/CO2 mixtures at different pH values for low salinity water-CO2 EOR (LSW-CO2 EOR) applications in Brazilian reservoirs. Brazilian light crude oil, pure CO2, and different brine solutions were used to represent the fluids in actual oil reservoirs. The experiments were carried out on Botucatu sandstone samples, with mineralogy determined by energy dispersive X-ray analysis. Coreflooding experiments were conducted by injection of 10 pore volumes of high salinity water followed by low salinity water. Contact angles, IFT and pH measurements at atmospheric and elevated pressures were performed in a high-pressure view cell (