Alusta, Gamal Abdalla (Heriot-Watt University) | Mackay, Eric James (Heriot-Watt University) | Collins, Ian Ralph (BP Exploration) | Fennema, Julian (Heriot-Watt University) | Armih, Khari (Heriot-Watt University)
This study has focused on the development of a method to test the economic viability of Enhanced Oil Recovery (EOR) versus infill well drilling where the challenge is to compare polymer flooding scenarios with infill well drilling scenarios, not just based on incremental recovery, but on Net Present Value as well.
In a previous publication (Alusta et al., 2011, SPE143300) the method was developed to address polymer flooding, but it can be modified to suit any other EOR methods. The method has been applied to a synthetic scenario with constant economic parameters, which has demonstrated the impact that oil price can have on the decision making process.
The method was then applied and tested (Alusta et al., 2012, SPE150454) with varied operational and economic parameters to investigate the impact in delaying the start of polymer flooding to identify whether it is better to start polymer flooding earlier or later in the life of the project. Consideration was also given to the optimum polymer concentration, and the impact that factors such as oil price and polymer cost have on this decision. Due to the large number of combined reservoir engineering and economic scenarios, Monte Carlo Simulation and advanced analysis of large data sets and the resulting probability distributions had to be developed.
In this paper the methodology is applied to an offshore field where the choice has already been made to drill infill wells, but where we test the robustness of the method against a conventional decision making process for which there is historical data. We do this by performing calculations that compare the infill well scenario chosen with a range of polymer flooding scenarios that could have been selected instead, to identify whether or not the choice to drill infill wells was indeed the optimum choice from an economic perspective.
We conclude from all the reservoir simulations and subsequent economic calculations that the decision to drill infill wells was indeed the optimum choice from an economic perspective.
Carbon dioxide (CO2) flooding is a conventional process in which the CO2 is injected into the oil reservoir to increase the quantity of extracting oil. This process also controls the amount of released CO2 as a greenhouse gas in the atmosphere which is known as CO2 sequestration process. However, the mobility of the CO2 inside the hydrocarbon reservoir is higher than the crude oil and always viscous fingering and gravity override problems occur during a CO2 injection. The most common method to overcome these problems is to trap the gas bubbles in the liquid phase in form of aqueous foam prior to CO2 injection. Although, the aqueous foams are not thermodynamically stable, the special care should be considered to ensure about bulk foam preparation and stability. Selection of a proper foaming agent from a large number of available surfactants is the main step in the bulk foam preparation. To meet this purpose, many chemical and crude oil based surfactants have been reported but most of them are not sustainable and have disposal problems. The objective of this experimental study is to employ Lingosulfonate and Alkyl Polyglucosides (APGs) as two sustainable foaming agents for the bulk foam stability investigations and foam flooding performance in porous media. In the initial part, the bulk foam stability results showed that APGs provided more stable foams in compare with Lingosulfonate in all surfactant concentrations. In the second part, the results indicated that the bulk foam stability measurements provide a good indication of foam mobility in porous media. The foaming agent’s concentration which provided the maximum foam stability also gave the highest value of mobility reduction in porous media.
Currently, many reservoirs in the region approach the end of primary recovery phase where new techniques are needed to enhance recovery. Therefore, the need to optimize oil recovery from the current resources is very well understood by regional oil companies. To enhance oil recovery from current oil resources, field operators need to overcome the forces responsible for oil entrapment. Enhanced Oil Recovery techniques (EOR) introduce new energy into oil reservoirs to reduce the influence of these forces. Most of these resources contain light oil and are considered suitable candidates for either miscible or chemical EOR techniques. The first technique is challenged by the availability of suitable miscible gas. While, chemical EOR techniques are challenges by the high salt concentrations in the maturing oil reservoirs. The high salinity conditions encourage deficiencies in the performance of chemical EOR processes. Therefore, minimizing the effect of in situ salt on the injected chemical would impose tremendous improvement that leads to higher oil recovery. One way to diminish salt effect is to condition the oil reservoirs by injecting a slug of preflush water prior to chemical injection.
In this paper, the performance of polymer flooding, after preflush slug, in high salinity reservoir is investigated by numerical simulation means. The injected slugs, both preflush and polymer, are driven by water. The objective is to identify the relationship between preflush, polymer, and drive water characteristics and oil recovery. Seven parameters were considered: preflush slug size, preflush salinity, polymer slug size, polymer concentration, polymer slug salinity, and drive water salinity. The results show that these parameters have various degree of influence on oil recovery. For example, increasing the preflush slug size would results in more oil recovery especially during the early time. Detailed findings will be presented in the paper.
Abou Sayed, Nada (Petroleum Institute) | Shrestha, Reena (The Petroleum Institute) | Sarma, Hemanta Kumar (The Petroleum Institute) | Al Kindy, Nabeela (The Petroleum Institute) | Haroun, Muhammad (University of Southern California) | Abdul Kareem, Basma Ali (The Petroleum Institute) | Ansari, Arsalan Arshad (The Petroleum Institute)
EOR technologies such as CO2 flooding and chemical floods have been on the forefront of oil and gas R&D for the past 4 decades. While most of them are demonstrating very promising results in both lab scale and field pilots, the thrive for exploring additional EOR technologies while achieving full field application has yet to be achieved. Among the emerging EOR technologies is the surfactant EOR along with the application of electrically enhanced oil recovery (EEOR) which is gaining increased popularity due to a number of reservoir-related advantages such as reduction in fluid viscosity, water-cut and increased reservoir permeability.
Experiments were conducted on 1.5?? carbonate reservoir cores extracted from Abu Dhabi producing oil fields, which were saturated with medium crude oil in a specially designed EK core flood setup. Electrokinetics (DC voltage of 2V/cm) was applied on these oil saturated cores along with waterflooding simultaneously until the ultimate recovery was reached. In the second stage, the recovery was further enhanced by injecting non-ionic surfactant (APG) along with sequential application of EK. This was compared with simultaneous application of EK-assisted surfactant flooding. A smart Surfactant-EOR process was done in this study that allowed shifting from sequential to simultaneous Surfactant-EOR alongside EEOR
The experimental results at ambient conditions show that the application of waterflooding on the carbonate cores yields recovery of approximately 46-72% and an additional 8-14% incremental recovery resulted upon application of EK, which could be promising for water swept reservoirs. However, there was an additional 6-11% recovery enhanced by the application of EK-assisted surfactant flooding. In addition, EK was shown to enhance the carbonate reservoir's permeability by approximately 11-29%. Furthermore, this process can be engineered to be a greener approach as the water requirement can be reduced upto 20% in the presence of electrokinetics which is also economically feasible.
In a layered, 2D heterogeneous sandpack with a 19:1 permeability contrast that was preferentially oil-wet, the recovery by waterflood was only 49.1% of original oil in place (OOIP) because of injected water flowing through the high-permeability zone, leaving the low-permeability zone unswept. To enhance oil recovery, an anionic surfactant blend (NI) was injected that altered the wettability and lowered the interfacial tension (IFT). Once IFT was reduced to ultralow values, the adverse effect of capillarity retaining oil was eliminated. Gravity-driven vertical countercurrent flow then exchanged fluids between high- and low-permeability zones during a 42-day system shut-in. Cumulative recovery after a subsequent foam flood was 94.6% OOIP, even though foam strength was weak. Recovery with chemical flood (incremental recovered oil/waterflood remaining oil) was 89.4%. An alternative method is to apply foam mobility control as a robust viscous-force-dominant process with no initial surfactant injection and shut-in. The light crude oil studied in this paper was extremely detrimental to foam generation. However, the addition of lauryl betaine to NI (NIB) at a weight ratio of 1:2 (NI:lauryl betaine) made the new blend a good foaming agent with and without the presence of the crude oil. NIB by itself as an IFT-reducing and foaming agent is shown to be effective in various secondary and tertiary alkaline/surfactant/foam (ASF) processes in water-wet 1D homogeneous sandpacks and in an oil-wet heterogeneous layered system with a 34:1 permeability ratio.
The Dykstra-Parsons method (Dykstra and Parsons 1950) is used to predict the performance of waterflooding in noncommunicating stratified reservoirs. Much interest has been shown recently in the application of the method to chemical flooding, particularly for the case of polymer injection used for mobility control. The original method assumes that the reservoir layers are horizontal; however, most oil reservoirs exhibit a dip angle, with water being injected in the updip direction. Therefore, it is important to account for the effect of inclination on the performance of the method.
A modification of the Dykstra-Parsons equations is obtained to account for reservoir inclination. The developed model includes a dimensionless gravity number that accounts for the effect of the dip angle and the density difference between the displacing and displaced fluids. The derived equation that governs the relative locations of the displacement fronts in different layers is nonlinear, includes a logarithmic term, and requires an iterative numerical solution. This solution is used to estimate the fractional oil recovery, the water cut, the injected pore volume, and the injectivity ratio at the time of water breakthrough in successive layers.
Solutions for stratified systems with log-normal permeability distribution were obtained and compared with horizontal systems. The effects of the gravity number, the mobility ratio, and the Dykstra-Parsons permeability-variation coefficient (VDP) on the performance were investigated. Cases of updip and downdip injection are discussed.
It was found that for a positive gravity number (updip water injection), performance is enhanced in terms of delayed water breakthrough, increased fractional oil recovery, and decreased water cut as compared with horizontal layers. This occurs for both favorable and unfavorable mobility ratios but is more evident in unfavorable mobility ratios and more-heterogeneous cases. For the case of a negative gravity number (downdip water injection or updip gas injection), the opposite behavior was observed.
The results were also compared with the performance of inclined communicating reservoirs with complete crossflow. The effect of communication between layers was found to improve fractional oil recovery for favorable and unit mobility ratios and decrease recovery for unfavorable mobility ratio.
This article reports a laboratory study of a novel alkaline/surfactant/foam (ASF) process. The goal of the study was to investigate whether foaming a specially designed alkaline/surfactant (AS) formulation could meet the two key requirements for a good enhanced oil recovery (EOR) [i.e., lowering the interfacial tension (IFT) considerably and ensuring a good mobility control]. The study included phase-behavior tests, foam-column tests, and computed-tomography (CT)-scan-aided corefloods. It was found that the IFT of the designed AS and a selected crude oil drops by four orders of magnitude at the optimum salinity. The AS proved to be a good foaming agent in the column tests and corefloods in the absence of oil. The mobility reduction caused by the AS foam was hardly sensitive to salinity and increased with decreasing foam quality. CT-scanned corefloods demonstrated that AS foam, after a small AS preflush, recovered almost all the oil left after waterflooding. The oil-recovery mechanism by ASF combines the formation of an oil bank and the transport of emulsified oil by flowing lamellae. Further optimization of the ASF is needed to ensure that the oil is produced exclusively by the oil bank.
The associative properties of hydrophobically modified water-soluble polymers (HMWSPs) are attractive for improved oil recovery (IOR) because of both their enhanced thickening capability, compared with classical water-soluble polymers (for mobility-control applications), and their permeability-reduction, or plugging, ability (for well-treatment applications). In previous works, we have studied the injectivity of HMWSP made of sulfonated polyacrylamide backbones and alkyl side chains in the dilute regime and have shown, in particular, that it was largely governed by adsorption. In this paper, we report new experimental data on the injectivity of the same class of HMWSP solutions in the semidilute regime.
From membrane filtration tests at imposed flow rate, we have first observed the formation of a filter cake made of HMWSP physical gel, which remained largely permeable to polymers. Our observations are compatible with the creation of channels within the gel. This leads to a gel-filtration process, entailing modifications of the solution's viscosimetric properties, which can be explained by a rearrangement of the intra- and interchain hydrophobic bonds in the solution. The second part of our work consisted of injectivity tests in model granular packs. We have performed comparative experiments in porous media with variable permeabilities, but at the same shear rate in the pore throats. Results show that, above a critical permeability kkC, or a critical pore-throat radius rpkC, HMWSP injection led to stable resistance factors, with values close to the solution?s viscosity, and that, at less than kkC or rpkC, the very high resistance factors observed suggest that flow-induced gelation of the HMWSP takes place. Furthermore, resistance factors measured over the core internal sections are compatible with an in-depth formation of the gel. These insights could be of use for designing HMWSP better suited to mobility-control operations and for tuning HMWSP injection conditions for profile/conformance-control operations.
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.
Screening and piloting of enhanced oil recovery (EOR) methods is often a lengthy process requiring large financial commitments. The reservoir uncertainty and, for some EOR methods, the lack of fundamental recovery mechanism understanding, call for a careful and staged screening and piloting program before committing to full-field implementation. The MicroPilot* single-well in situ EOR evaluation is a new piloting technique which allows for rapid and cost effective testing of EOR methods under in-situ downhole conditions. It is a log-inject-log technique conducted with a wireline formation tester, where a small quantity of EOR fluid is injected and the resulting change in oil saturation then determined based on a set of openhole logs that are run both before and after the injection.
The MicroPilot is a proven piloting technology for alkaline-surfactant-polymer (ASP) EOR. In this paper, we investigate the feasibility of extending this new technology for testing of CO2 EOR. We demonstrate through detailed analytical and numerical modeling that the changes in oil saturation and composition expected during the CO2 EOR process are measurable by the openhole logs when taking into account logging tool resolution. Based on a test library consisting of 13 different oils, which have been carefully characterized to match experimental PVT data, and all of which are likely candidate oils for miscible CO2 EOR, we investigate the expected pilot response when injecting CO2 both above and below the minimum miscibility pressure. We further study the sensitivity of the pilot response to gravity effects as well as residual oil saturation to the CO2 flood.