Shubham, Agrawal (Texas A&M University at Qatar) | Martavaltzi, Christina (Texas A&M University at Qatar) | Dakik, Ahmad Rafic (Texas A&M University at Qatar) | Gupta, Anuj (Texas A&M University at Qatar)
It is well known that the majority of carbonate reservoirs are neutral to oil-wet. This leads to much lower oil recovery during waterflooding since there is no spontaneous imbibition of water in heterogeneous reservoir displacement. It has been verified by a number of researchers that Adjustment of ion concentration in brine solutions, or adding surfactant solutions can enhance the oil recovery by altering the wettability. In the published literature, contact angle studies usually refer to measurement on calcite crystals and there are no results for the contact angle of carbonate porous media representative of reservoir rocks. Moreover, there are few studies on the effect of non-ionic surfactants, compared to those for ionic surfactants. Understanding the effect of various ions and their concentration in the injection brine on the wettability of the Limestone outcrop core samples is the first step for tailoring of the optimum injection brine. This will be followed by a study of the effect of surfactant on the wettability of calcite crystal samples. The evaluation of the results may provide guidelines for the design of injection brines for efficient enhanced oil recovery from carbonate reservoirs.
In this work, a procedure is established for the measurement of the contact angle on limestone outcrop core samples. Results showed that, at atmospheric conditions, low salinity CaCl2 solution induced the most significant improvement on the wettability of the outcrop sample. Moreover, among all the non-ionic surfactants studied, only the presence of the two first members of the 15S analogous series might lead to a slight decrease of the contact angle.
Fitts, J.P. (Dept. of Civil & Environmental Engineering, Princeton University) | Ellis, B.R. (Dept. of Civil & Environmental Engineering, Princeton University) | Deng, H. (Dept. of Civil & Environmental Engineering, Princeton University) | Peters, C.A. (Dept. of Civil & Environmental Engineering, Princeton University)
Scale prevention is important to ensure continuous production from existing reserves that produce brine. Wells could be abandoned prematurely because of poor management of scale and corrosion. The objective of this paper is to present an overview of scale prediction and control and the current research at Rice University to solve these problems. In this paper, the challenges of scale prediction at high temperature, high pressure, and high total dissolved solids (TDS) and an accurate model to predict pH, scale indices, density, and inhibitor needs at these conditions are discussed and reviewed: specifically discussed are (1) the various scale types found in oil and gas production and the condition under which they form; (2) the relationship of pH, alkalinity, organic acids, carbonates, and CO2 distribution; (3) the temperature (T), pressure (P), TDS dependence of the thermodynamic equilibrium constants and activity coefficients; and (4) the accuracy of the Pitzer ion-interaction model-based scale-prediction algorithms and their application. On the basis of a simple propagation of error estimation, the overall estimated error for calcite saturation index (SI) is ± 0.1. This algorithm has been validated with literature solubility data for six minerals in the T, P, and TDS range of 0 to 200°C, 0 to 15,000 psia, and 0 to 350 000 mg/L TDS; for pH data at 25 and 60°C; and density of weighting fluids with density between 8 and 12.7 lbm/gal.
In order to assess scaling risk in pipes, a better understanding of scale deposition kinetics on steel surface under realistic and complex oil field condition is needed. In this paper, we introduce the development of a novel CaCO3 pre-coated steel tubing for studies of CaCO3 crystal growth kinetics and inhibition kinetics at oilfield conditions. This approach provides a relatively stable surface area and eliminates the limits of laboratory batch experiments. Initially, the heterogeneous precipitation rate of CaCO3 from a supersaturated solution (Calcite SI=0.3-0.7) was evaluated at specific temperatures (60-80???C), linear velocities (0.01-0.75 cm/sec), and ionic strengths (0.1-1M). The curve fitted heterogeneous precipitation rate constant, kppt, ranged from 10 -5 to10 -4 cm/sec. The results are comparable to that calculated from the Sieder and Tate equation, which indicates that the crystal growth was dominated by mass transfer rate. With the injection of scale inhibitors for one hour through the pre-coated tubing, the calcium carbonate precipitation can be prevented for days, and the crystal growth rate can be significantly slowed down. Not only does this study contribute to the limited data base of scaling kinetics in actual flowing pipes, but also provides a new approach to better understand the inhibitor reaction with the subsurface. The approach and results will assist in the prediction of scaling risk as a function of brine composition, well conditions and scale inhibitor composition, which will improve our ability to predict the severity of scale risk, including the rate of scaling, minimum blockage time, and thus the minimum inhibitory concentration needed in actual flowing pipes.
The ultra-high temperature (150-250oC), pressure (1,000-2,000 bar, 15,000 to 30,000 psi) and TDS (>300,000 mg/L) in deepwater oil and gas production pose significant challenges to scaling control due to limited knowledge of mineral solubility, kinetics and inhibitor efficiency at these extreme conditions. Prediction of thermodynamic properties of common minerals is currently limited by lack of experimental data and inadequate understanding of modeling parameters. In this study, a new apparatus was built to test scale formation and inhibition at high temperatures and pressures. Solubilities of two common minerals, barite and calcite, were tested at temperature up to 250oC, pressure up to 1,500 bar (22,000 psi) and ionic strength up to 6m in solutions with elevated concentrations of mixed electrolytes (e.g., calcium, magnesium, sulfate and carbonate) representing the maximum range of interferences expected (95%CI) in oil and gas wells. As an attempt towards experimentally determining mineral solubility at high temperature, pressure and salinity, not only does this study contribute to the extremely limited data base, but it also provides a reliable approach for evaluating and adjusting model predictions at extreme conditions. Predictions by a thermodynamic model based on Pitzer's ion interaction theory were evaluated using experimental data. The dependence of Pitzer's coefficients for ion activity coefficients on temperature and pressure was examined and incorporated into the scale prediction model, whose prediction is consistent with both experimental and literature data at all conditions tested.
Cyclic steam EOR pilot project has been deployed in sandstone reservoir type, heavy oil field of Petroleum Development Oman, South Operation, and recently within August to October 2011 showing an interesting CO2 increase from 1% to the level of 25% mol in gas phase as phenomena. This paper discuss the implementation of Root Cause Analysis, developing steam core flood techniques to understand the increasing mechanism of CO2, and the proactive well surveillance will help to monitor accurately the increasing level and the impact. The impact of high CO2 to well and operation integrity also have been studied. The Low GOR (<25 scf/bbl) found to be a limitation of reservoir, while the heavy oil characteristics 14 API will limit a level increase from the well. The only possible CO2 increased are coming from a thermal evaporation mechanism of formation water and rock mineralogy. The basis simplified chemistry model have been developed as steam energy reaction, one mole of CO2 was produced for each mole of H2O injected at steam temperatures. From the detail mineralogy study found that the sandstone reservoir from the field containing Dolomite and Calcite. The surface CO2 found to be the total amount of evaporation from rock mineralogy, Calcite from formation water and from origin associate reservoir gas. And finally, the CO2 percentage increase in the surface will be less than 3 scf/bbl.
The conductivity of an acid-etched fracture depends strongly on void spaces and channels along the fracture resulting from uneven acid etching of the fracture walls. In this study, we modeled the deformation of the rough fracture surfaces acidized in heterogeneous formations based on the synthetic permeability distributions and developed a new correlation to calculate the acid-etched fracture conductivity.
In our previous work, we modeled the dissolution of the fracture surfaces in formations having small-scale heterogeneities in permeability. The characterization of the correlated permeability fields of rock includes the average permeability, normalized correlation lengths in both horizontal and vertical directions, and normalized standard deviation. These statistical parameters have a significant influence on the fracture-etching profiles obtained from the model. Beginning with this fracture-width distribution, we have modeled the deformation of the fracture surfaces as closure stress is applied to the fracture. The elastic properties of the rock, such as Young's modulus and Poisson's ratio, have effects on the size of the spaces remaining open after fracture closure. After the model yields the width profile under closure stress, the overall conductivity of the fracture is then obtained by numerically modeling the flow through this heterogeneous system.
In this paper, we introduce our models and investigate the effects of permeability and mineralogy distributions and rock elastic properties on the overall conductivity of an acid-etched fracture. A new acid-fracture conductivity correlation is developed on the basis of many numerical experiments.
The goal of this work is to pursue strategies to improve oil recovery in highly fractured carbonate reservoirs by altering the wettability from oil-wet to preferentially water-wet at high temperature (100oC or above), high salinity, and especially high hardness environments. Cationic surfactants and anionic surfactants were investigated for their compatibility with hard brine and thermal/hydrolytic stability. Sequestration agents were added to improve aqueous solubility. The performance of surfactant formulations was evaluated by measuring contact angles on calcite plates and spontaneous imbibition in originally oil-wet dolomite cores. Cationic surfactants altered the wettability of oil-aged calcite plates towards a more water-wet state in the presence of hard brines; oil recovery by spontaneous imbibition from dolomite cores was 50-65% OOIP. Anionic surfactant formulations changed the carbonate wettability to strongly water-wet only when the brine salinity and divalent ion concentration were reduced. The wettability could be altered in hard brines if a sequestration agent (e.g. EDTA) is added to anionic surfactant formulations; up to 45% OOIP was recovered by spontaneous imbibitions. EDTA provides alkalinity, saponification, chelation of divalent ions, and dissolution of dolomite; these mechanisms are responsible for the increase in imbibition rate and ultimate oil recovery in fractured carbonates.
Carbonate reservoirs (dolomites and limestones) account for approximately a half of world hydrocarbon reserves and many of them are naturally fractured (Roehl and Choquette, 1985). Fractured carbonate reservoirs are a class of reservoirs characterized by high conductivity fractures surrounding low permeability matrix blocks. In these reservoirs, the production relies on the imbibition of the injection fluid by the matrix blocks which expel the oil into the fracture network which, in turn, transport it to the production wells. Water imbibes into the matrix blocks if the reservoir rock is water-wet. However, extensive research work by Chilingar and Yen (1983) shows that most carbonate reservoirs are mixed-wet to oil-wet. The oil recovery from conventional waterflooding of fractured carbonate reservoirs is low due to poor imbibition of water into oilwet matrix. On average, primary and water flooding methods leave about 80% of the original oil in place (OOIP) in fractured carbonate reservoirs.
Very few EOR processes work for fractured oil-wet carbonates and many of them have to rely on gravity drainage if the formation is highly fractured. Miscible gas injection, steam injection, and chemical treatment, have been considered to recover oil from highly fractured oil-wet carbonates reservoirs (Christiansen et al. 1990, Al-Hadhrami et al. 2000, Shahin et al. 2006). Chemical enhanced oil recovery in carbonate reservoirs has been studied for many years and has gained more interest in recent years due to high oil prices. Surfactant-mediated wettability alteration has received more attention recently because carbonate formations are much more likely to be fractured and oil-wet. In highly fractured reservoir, surfactant solutions are injected with the aim of changing the wettability of the matrix to a more water-wet state, hence enhancing the spontaneous imbibition process, leading to a higher oil recovery (Fig. 1).
Wettability is defined as "the tendency of one fluid to spread on or adhere to a solid surface in the presence of other immiscible fluids?? (Craig, 1971). Wettability affects capillary pressure, relative permeability and residual oil saturation (Anderson 1986a, and 1986b). The extensive research on the interaction between crude oil, brine, and rock (COBR) indicates the wettability alteration depends on aging time, temperature, water saturation, crude oil composition, brine composition and rock surface (Buckley 2001, Jadhunandan & Morrow 1995). It is widely believed that asphaltenes and other high molecular weight polar components of crude oil are responsible for altering the wetting of reservoir rocks. Buckley (1996, 1998)
Coordination chemistry models of oil adhesion to sandstones and calcite allow more precise testing of wettability alteration theories. The primary electrostatic bonds calculated to link oil to most sandstones are oil -NH+ and kaolinite edge >Al-OH2+ sites at pH < 5.5, and oil -COOCa+ and kaolinite edge >Al:Si-O- sites at pH > 5.5; -NH+ and -COOCa+ can also exchange onto basal planes. Low salinity waterfloods should break -NH+ --- >AlOH2+ bonds at pH < 5.5 and low salinity, low Ca+2 waterfloods are calculated to eliminate -COOCa+ --- >Al:Si-O- bonds at pH > 5.5. Oil is calculated to link electrostatically to calcite through oil - COO- and >CaOH2+ sites, and to a lesser extent through oil -NH+ and calcite >CO3- sites. Sulfate-rich floods are calculated to eliminate >CaOH2+ charge through sulfate sorption. Divalent cation (Ca+2 and Mg+2) - rich floods are calculated to reverse -COO- charge through sorption.
KEYWORDS: Enhanced oil recovery, low salinity waterfloods, mineral surface chemistry.