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.
Excessive water production from unwanted zones in oil producing wells is one of the major challenges faced by the oil industry. The applicability of organically crosslinked polymer (OCP) systems as sealants for water shutoff treatments in temperatures up to 350°F is well documented. However, their effectiveness at temperatures above 350°F has not been evaluated. This paper presents experimental data from using an OCP system for water shutoff treatments at 400°F.
At temperatures around 400°F, crosslinking is expected to happen faster and can lead to premature gelation of the recipe before the entire treatment is in place. Thus, controlling the gelation time at such temperatures is extremely crucial. Optimizing the amount of retarder is essential to provide adequate time for placement of the treatment fluid. This paper provides gelation time data at temperatures between 350 and 400°F with different amounts of retarder. With an optimum amount of retarder, the OCP showed a gelation time of 1 hr 20 min.
This paper also describes the experimental setup used to study and determine the long-term stability of the OCP system at 400°F. Sand packs measuring 1-ft long were used for the test to simulate formation conditions. Once the optimized OCP recipe was gelled inside the sand pack, measurements were taken by gradually applying incremental differential pressure (?P) to evaluate the sealant at temperature, as well as the threshold ?P the system could withstand. Even after one month at 400°F, the OCP recipe was able to sustain a ?P of 950 psi over the sand pack.
The data indicates the applicability of this system as an effective conformance product to shut off water-producing zones over an extended period of time at 400°F.
In a past decade, various nanoparticle experiments have been initiated for improved/enhanced oil recovery (IOR/EOR) project by worldwide petroleum researchers and it has been recognized as a promising agent for IOR/EOR at laboratory scale. A hydrophilic silica nanoparticle with average primary particle size of 7 nm was chosen for this study. Nanofluid was synthesized using synthetic reservoir brine. In this paper, experimental study has been performed to evaluate oil recovery using nanofluid injection onto several water-wet Berea sandstone core plugs.
Three injection schemes associated with nanofluid were performed: 1) nanofluid flooding as secondary recovery process, 2) brine flooding as tertiary recovery processs (following after nanofluid flooding at residual oil saturation), and 3) nanofluid flooding as tertiary recovery process. Interfacial tension (IFT) has been measured using spinning drop method between synthetic oil and brine/nanofluid. It observed that IFT decreased when nanoparticles were introduced to brine.
Compare with brine flooding as secondary recovery, nanofluid flooding almost reach 8% higher oil recovery (% of original oil in place/OOIP) onto Berea cores. The nanofluid also reduced residual oil saturation in the range of 2-13% of pore volume (PV) at core scale. In injection scheme 2, additional oil recovery from brine flooding only reached less than 1% of OOIP. As tertiary recovery, nanofluid flooding reached additional oil recovery of almost 2% of OOIP. The IFT reduction may become a part of recovery mechanism in our studies. The essential results from our experiments showed that nanofluid flooding have more potential in improving oil recovery as secondary recovery compared to tertiary recovery.
The oil and gas industry must face the challenges to unlock the resources that are becoming increasingly difficult to reach with conventional technology. Most oil fields around the world have achieved the stage where the total production rate is nearing the decline phase. Hence, the current major challenge is how to delay the abandonment by extracting more oil economically. The latest worldwide industries innovation trends in miniaturization and nanotechnology material. A nanoparticle, as a part of nanotechnology, has size typically less than 100 nm. Its size is much smaller than rock pore throat in micron size. A nanoparticle fluid suspension, so called nanofluid, is synthesized from nano-sized particles and dispersed in liquids such as water, oil or ethylene glycol.
Through continuously increasing of publication addressed on the topic, nanofluid has showed its potential as IOR/EOR in the past decade. It has motivated us to perform research study to reveal the recovery mechanism and performance of nanofluid in porous medium. We focus on liphopobic and hydrophilic silica nanoparticles (LHP). Miranda et al. (2012) has mentioned the benefit of using silica nanoparticles. It is inorganic material that easier produced with a good degree of control/modify of physical chemistry properties. It can also be easily surface functionalized from hydrophobic to hydrophilic by silanization with hydroxyl group or sulfonic acid. Ju et al. (2006) has initially observed LHP with size range 10-500 nm could improve oil recovery with around 9% (with LHP concentration 0.02 vol. %) compared with pure water. They explained that the recovery mechanism involves wettability alteration of reservoir rock due to adsorbed LHP. Besides, they also reported the porosity and permeability impairment of sandpacks during nanofluid flooding.
Some coreflood literature points to the initial wettability state undergoing change during waterflooding, usually towards water-wetness. The current study aimed to directly probe the adsorbed/deposited oil components on model silicate substrates prior to and after flooding. Bare glass and kaolinite-coated glass in the initial brine were drained with crude oil and aged, after which the oil was displaced with the flooding brine. For a matrix of initial and flood brines (comprising sodium and calcium) of varying salinity and/or pH, the oil remaining on the substrates was analyzed by high-resolution scanning electron microscopy, contact angle and spectroscopy. On glass, the oil layer contacting it in the initial (aged) state retracts and detaches during flooding, to typically leave individual oil nanodroplets separated by clean substrate. Brines less able to overcome the oil-glass adhesion displayed a higher coverage of more irregularly shaped, semiretracted drop-lets and a higher frequency of larger microscopic residues. On kaolinite-coated glass, the added porosity and roughness increased the presence of these adhering, stranded residues. On bare glass, the residual deposit after high salinity floodingis generally least at intermediate flood pH 6, while residues decrease with decreasing pH of low salinity floods. However, on kaolinite-coated substrates, residual deposit is greatest after flooding at intermediate pH 6, and also increases on reduction of flood salinity
Jin, Min (Heriot-Watt University) | Pickup, Gillian (Heriot-Watt University) | Mackay, Eric (Heriot-Watt University) | Todd, Adrian (Heriot-Watt University) | Sohrabi, Mehran (Heriot-Watt University) | Monaghan, Alison (British Geological Survey) | Naylor, Mark (University of Edinburgh)
Estimation of carbon dioxide (CO2)-storage capacity is a key step in the appraisal of CO2-storage sites. Different calculation methods may lead to widely diverging values. The compressibility method is a commonly used static method for estimating storage capacity of saline aquifers: It is simple, is easy to use, and requires a minimum of input data. Alternatively, a numerical reservoir simulation provides a dynamic method that includes Darcy flow calculations. More input data are required for dynamic simulation, and it is more computationally intensive, but it takes into account migration pathways and dissolution effects, so it is generally more accurate and more useful. For example, the CO2-migration plume may be used to identify appropriate monitoring techniques, and the analysis of the trapping mechanism for a certain site will help to optimize well location and the injection plan.
Two hypothetical saline-aquifer storage sites in the UK, one in Lincolnshire and the other in the Firth of Forth, were analyzed. The Lincolnshire site has a comparatively simple geology, while the Forth site has a more complex geology. For each site, both static- and dynamic-capacity calculations were performed. In the static method, CO2 was injected until the average pressure reached a critical value. In the migration-monitoring case, CO2 was injected for 15 years, and was followed by a closure period lasting thousands of years. The fraction of dissolved CO2 and the fraction immobilized by pore-scale trapping were calculated.
The results of both geological systems show that the migration of CO2 is strongly influenced by the local heterogeneity. The calculated storage efficiency for the Lincolnshire site varied between 0.34 and 0.65% of the total pore-volume, depending on whether the system boundaries were considered open or closed. Simulation of the deeper, more complex Forth geological system gave storage capacities as high as 1.05%.
This work was part of the CO2-Aquifer-Storage Site Evaluation and Monitoring (CASSEM) integrated study to derive methodologies for assessment of CO2 storage in saline formations. Although static estimates are useful for initial assessment when fewer data are available, we demonstrate the value of performing dynamic storage calculations and the opportunities to identify mechanisms for optimizing the storage capacity.
For ultratight shale reservoirs, wettability strongly affects fluid flow behavior. However, wettability can be modified by numerous complex interactions and the ambient environment, such as pH, temperature, or surfactant access. This paper is a third-phase study of the use of surfactant imbibition to increase oil recovery from Bakken shale. The surfactant formulations that we used in this paper are the initial results that are based on our previous study, in which a group of surfactant formulations was examined--balancing the temperature, pH, salinity, and divalent-cation content of aqueous fluids to increase oil production from shale with ultralow porosity and permeability in the Middle Member of the Bakken formation in the Williston basin of North Dakota. In our previous study, through the use of spontaneous imbibition, brines and surfactant solutions with different water compositions were examined. With oil from the Bakken formation, significant differences in recoveries were observed, depending on compositions and conditions. Cases were observed in which brine and surfactant (0.05 to 0.2 wt% concentration) imbibition yielded recovery values of 1.55 to 76% original oil in place (OOIP) at high salinity (150 to 300 g/L; 15 to 30 wt%) and temperatures ranging from 23 to 120°C. To advance this work, this paper determines the wettability of different parts of the Bakken formation. One goal of this research is to identify whether the wettability can be altered by means of surfactant formulations. The ultimate objective of this research is to determine the potential of surfactant formulations to imbibe into and displace oil from shale and to examine the viability of a field application. In this paper, through the use of modified Amott-Harvey tests, the wettability was determined for cores and slices from three wells at different portions of the Bakken formation. The tests were performed under reservoir conditions (90 to 120°C, 150- to 300-g/L formation-water salinity), with the use of Bakken crude oil. Both cleaned cores (cleaned by toluene/methanol) and untreated cores (sealed, native state) were investigated. Bakken shale cores were generally oil-wet or intermediate-wet (before introduction of the surfactant formulation). The four surfactant formulations that we tested consistently altered the wetting state of Bakken cores toward water-wet. These surfactants consistently imbibed to displace significantly more oil than brine alone. Four of the surfactant imbibition tests provided enhanced-oil-recovery [(EOR) vs. brine water imbibition alone] values of 6.8 to 10.2% OOIP, incremental over brine imbibition. Ten surfactant imbibition tests provided EOR values of 15.6 to 25.4% OOIP. Thus, imbibition of surfactant formulations appears to have a substantial potential to improve oil recovery from the Bakken formation. Positive results were generally observed with all four surfactants: amphoteric dimethyl amine oxide, nonionic ethoxylated alcohol, anionic internal olefin sulfonate, and anionic linear a-olefin sulfonate. From our work to date, no definitive correlation is evident in surfactant effectiveness vs. temperature, core porosity, core source (i.e., Upper Shale or the Middle Member), or core preservation (sealed) or cleaning before use.
Xing, Dazun (University of Pittsburgh) | Wei, Bing (University of Pittsburgh) | McLendon, William J. (University of Pittsburgh) | Enick, Robert M. (University of Pittsburgh) | McNulty, Samuel (University of Pittsburgh) | Trickett, Kieran (University of Bristol) | Mohamed, Azmi (University of Bristol) | Cummings, Stephen (University of Bristol) | Eastoe, Julian (University of Bristol) | Rogers, Sarah (ISIS Facility Science and Technology Facilities Council) | Crandall, Dustin (URS Washington Division) | Tennant, Bryan (URS Washington Division) | McLendon, Thomas (US Department of Energy National Energy Technology Laboratory) | Romanov, Vyacheslav (US Department of Energy National Energy Technology Laboratory) | Soong, Yee (US Department of Energy National Energy Technology Laboratory)
Several commercially available, nonionic surfactants were identified that are capable of dissolving in carbon dioxide (CO2) in dilute concentration at typical minimum- miscibility-pressure (MMP) conditions and, upon mixing with brine in a high-pressure windowed cell, stabilizing CO2-in-brine foams. These slightly CO2-soluble, water-soluble surfactants include branched alkylphenol ethoxylates, branched alkyl ethoxylates, a fatty-acid-based surfactant, and a predominantly linear ethoxylated alcohol. Many of the surfactants were between 0.02 to 0.06 wt% soluble in CO2 at 1,500 psia and 25°C, and most demonstrated some capacity to stabilize foam. The most- stable foams observed in a high-pressure windowed cell were attained with branched alkylphenol ethoxylates, several of which were studied in high-pressure small-angle-neutron-scattering (HP SANS) tests, transient mobility tests using Berea sandstone cores, and high-pressure computed-tomography (CT)-imaging tests using polystyrene cores. HP SANS analysis of foams residing in a small windowed cell demonstrated that the nonylphenol ethoxylate SURFONIC® N-150 [15 ethylene oxide (EO) groups] generated emulsions with a greater concentration of droplets and a broader distribution of droplet sizes than the shorter-chain analogs with 9-12 ethoxylates. The in-situ formation of weak foams was verified during transient mobility tests by measuring the pressure drop across a Berea sandstone core as a CO2/surfactant solution was injected into a Berea sandstone core initially saturated with brine; the pressure-drop values when surfactant was dissolved in the CO2 were at least twice those attained when pure CO2 was injected into the same brine-saturated core. The greatest mobility reduction was achieved when surfactant was added both to the brine initially in the core and to the injected CO2. CT imaging of CO2 invading a polystyrene core initially saturated with 5 wt% KI brine indicated that despite the oil-wet nature of this medium, a sharp foam front propagated through the core, and CO2 fingers that formed in the absence of a surfactant were completely suppressed by foams formed because of the addition of nonylphenol ethoxylate surfactant to the CO2 or the brine.
Tariq, Syed M. (Zakum Development Co.) | Samad, Saleh A. (Abu Dhabi Marine Operating Co.) | Ben Aouda, Abdel Hakim (ZADCO) | Afzal, Muhammad (Zakum Development Co.) | Bengherbia, Mourad (ZADCO) | Graham, Gordon Michael (Scaled Solutions Limited)
A common flow assurance problem during waterflooding operations is the deposition of mineral scale due to mixing of incompatible brines. Deposition of mineral scale can occur anywhere in the production system (reservoir, near wellbore, wellbore, surface facilities) if certain conditions for deposition of scale are present (composition of mixed brine, dynamics of mixing, pressure, temperature and kinetics). Understanding where and how scale will deposit and its impact on production and operations is important especially for the mega offshore field development projects which use new generation of high value wells (long/multi laterals, MRC) associated downhole equipment (ICD, ICV, etc) and surface facilities. In this paper, we present a systematic approach to assessing the scale deposition risk with an example of the application to a giant carbonate field, offshore Abu Dhabi.
Advanced Ion Management (AIM) is an enhanced oil recovery (EOR) process where waterflood injection water is modified by the addition, removal, or dilution of ions. AIM can yield an increase in oil recovery compared to waterflooding using formation brines. To better understand the oil recovery mechanism of AIM in carbonates, ion chromatography studies and salt solubility measurements were conducted on AIM brines used in floods of Middle Eastern core.
The ion composition of the brines - upon mixing after extended time, at reservoir temperature and pressure, and after core flooding - were compared to elucidate the ion composition changes during an AIM waterflood and how those changes could lead to additional oil recovery. That knowledge could potentially be used to screen reservoir rock types and available water sources to determine which would be best suited for EOR from AIM waterflooding.
AIM technology encompasses a wide range of injection brines, and thus this ion chromatography analysis covers a range of modified brines, including brines for which analyses have not been previously published. Analysis of the results has implications for how ion composition may be correlated with oil recovery and what facilities are required to obtain the desired composition. The study finds that neither rock dissolution nor ion exchange alone is sufficient to explain oil recovery with modified brine injection, and neither mechanism is a guarantee of additional oil recovery. It also finds that sodium phosphate, borax, and sodium sulfate all precipitate divalent cations from seawater at field operating conditions.
This paper describes a combination of reservoir drilling fluid (RDF) and filter-cake breaker technology applied on four extended reach wells offshore Abu Dhabi which and provided multiple improvements in production rates of long horizontal laterals . The need for clean-up acid stimulations was reduced or eliminated in wells that could be beyond the reach of coil tubing.
The paper highlights the field implementation of these fluid systems and details the laboratory developmental work that coincided with the drilling and completion campaign. Three wells have been drilled with specialized reservoir drilling fluids (RDF) that included a premium grade xanthan, modified starch, carbonate with an internal filter cake breaker. Premium lubricants were included in the RDF to ensure that the drilling BHA could reach the ± 20,000 ft target depth and the liners could be run all the way to bottom. Acid stimulation of the nearly 10,000 ft reservoir sections was planned. The first two wells were drilled successfully, liners were run to bottom and the internal breaker was activated by a slightly acidic pH. The acid stimulation has only been performed on them to improve the initial production rate which was already near the expected target rate, while acid stimulation was not required for the third well as its performance has met the expected production rates. Subsequently, the fourth well utilized a more comprehensive cake breaker system and improved lubricant. Results of this well met production expectations also without the need for acid stimulation. Details of each well performance, field operations and results, including the laboratory development program are thoroughly discussed. Furthermore, impact of lubricants on RDF rheological properties, drilling performance and liner running torque and drag is detailed. In addition, the influence of reservoir drilling fluid design, lubricants and delay additives on the performance of the breaker is identified.