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.
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.
Dang, Cuong Thanh Quy (University of Calgary) | Nguyen, Ngoc Thi Bich (Sejong University - Korea) | Chen, Zhangxing (Sejong University - Korea) | Nguyen, Huy Xuan (Sejong University - Korea) | Bae, Wisup (Vietsovpetro JV) | Phung, Thuoc H
Chemical flooding, especially alkaline/polymer/surfactant (ASP) flooding is of significant increasing interest in mature reservoirs because of high oil prices and larger energy demands. However, it is a very complicated process, and the success of ASP has been mostly demonstrated in laboratory scale. Additionally, ASP is very sensitive to reservoir heterogeneity; therefore, it is urgent and necessary to have a comprehensive investigation of ASP flooding in different reservoir types for a wider and more successful implementation.
This paper aims to solve the prior problems for achieving a new insight vision of ASP flooding. Firstly, a series of laboratory experiments were conducted to optimize the ASP solution. A new mixture of single and double tail anionic surfactant was proposed as a promising approach for high temperature and hardness reservoirs. These mixtures are also more compatible with polymer and increase the optimum salinity. All of the important factors such as alkaline/polymer/surfactant concentration, pH, temperature, salinity, ionic strength were taken in account. And, the experimental result was analyzed by experimental design techniques which allow for evaluating the interaction among those factors which were usually eliminated in literature.
Laboratory experiments and simulations showed that for an Austrian oil reservoir, oil recovery can be significantly increased using polymers. One of the key design parameters for optimizing displacement efficiency while minimizing costs is the in-situ viscosity of the polymer solutions.
Whereas the viscosity of polymer solutions can be measured at surface, the viscosity in the reservoir is difficult to estimate due to degradation of the polymers during the injection process. In addition, polymers exhibit non-Newtonian behaviours resulting in different viscosities of the polymer solutions depending on the shear rate in the reservoir.
For the Austrian reservoir, water injection fall off tests were available. A simulation model was calibrated with these tests, and used to simulate injections of polymer solutions followed by fall offs. Simulation results indicate that water injection and fall off tests followed by a series of polymer injection and fall off tests can be interpreted to determine the in-situ viscosity of polymer solutions and the radius of the polymer front with reasonable accuracy, even in the case of non-Newtonian shear-thinning behaviour.
Being able to determine the in-situ viscosity allows modifying the injection programme ( changing pumps, modifying perforations) if the degradation of the polymer viscosity is found to be significant, and adjusting the polymer concentration to improve stability and efficiency of the displacement process.
The injectivity of sulfonated polymer solutions in carbonate reservoir rocks was investigated to evaluate the performance and feasibility of the polymer in the porous media under reservoir conditions. A sulfonated polyacrylamide with a sulfonation degree of 25 mole% was selected for this study. Polymer solutions at 0.1 wt% and 0.2 wt% in seawater were injected into carbonate core plugs with a permeability ranging from 100~600 mD at reservoir temperature and pressure. Two critical parameters, the resistance factor and residual resistance factor, were obtained in the tests. The resistance factor represents a quantitative measure of the mobility reduction during the propagation of the polymer solution in the porous media, while residual resistance factor is a measure of permeability reduction after the polymer treatment. The resistance factor is 5 ~ 8 at a flow rate of 0.5cc/min for 0.1 wt% polymer solution. The residual resistance factor is 1.24 ~ 1.34 for seawater injection after the polymer injection. Meanwhile, the resistance factor is 50~65 at a flow rate of 0.5cc/min for 0.2 wt% polymer solution. The residual resistance factor is 1.48~2.17. It is found that resistance factor increases significantly with flow rate, while residual resistance factor decreases with flow rate. The investigation of adsorbed polymer layer based on the permeability reduction provides insights into the performance of the selected polymer in the carbonate cores.
Surfactant-polymer (SP) flooding is one of the chemical EOR processes that are used to recover residual oil saturation. In high salinity/high hardness and high temperature applications many chemical flooding methods would not be effective. During the 80's BP proposed low-tension polymer flooding (LTPF) method to overcome some of the challenges caused by using high concentration of surfactant during some early SP flooding projects and to reduce the cost of operation. Amphoteric surfactant shows high thermal and chemical stability in these environments was evaluated in this study.
An experimental study was conducted to evaluate the performance of the low-tension polymer flooding (LTPF) process in recovering water flood residual oil using two types of amphoteric surfactants, two types of anionic surfactants, and two types of polymers that are suggested to be used for high salinity / high hardness at elevated temperature. Surface and interfacial tension, zeta potential and core flood experiments were conducted to study the surfactant-polymer interaction at high salinity brine, ability of the solution to lower IFT, surface charge to predict chemical retention, tertiary oil recovery, oil cut and pressure drop during chemical propagation in the porous media. In this study Berea sandstone cores with 1.5 in. diameter and 20 in. length were used to determine the above parameters. The core flood experiments were conducted at temperature and brine salinity of 95o C and around 172,000 ppm, respectively.
Amphoteric surfactant showed association with two types of polymers, HPAM and AMPS that caused reduction in surface activity until polymer-free aggregate concentration was reached. Increasing polymer concentration increases the surfactant concentration needed to reach to polymer-free aggregate concentration. When HPAM polymer used in preparing chemical slug, it shows higher injectivity decline compared to AMPS. Anionic surfactant showed less chemical retention due to the negative surface charge on Berea sandstone particles when this type of surfactant is used. No significant recovery was obtained during surfactant flooding, which prove that IFT reduction can't improve recovery without the aid of mobility control by polymers.
Relatively high oil prices, modest polymer prices, and advances that promote higher injectivity for polymer solutions have allowed polymer flooding to be applied in reservoirs with notably more viscous oils than in previous years. This paper describes a polymer flooding pilot project in the Tambaredjo field in Suriname. The average viscosity of the produced oil is ~1,700 cp, but solution gas reduces the effective oil viscosity in the reservoir to 400-600 cp (through the "foamy oil?? mechanism). Interestingly, the primary drive mechanism in the pilot area is compaction—leading to ~20% OOIP recovery. Because various restrictions preclude application of thermal methods, polymer flooding was explored as a means to enhance oil recovery. The average permeability of the sand exceeds 4darcys, but the level of heterogeneity is significant (>10:1 permeability contrast is common). The first simulation efforts suggested that injection of 25-40-cp polymer solutions might be optimum, considering both displacement and injectivity. Consequently, ~40-cp polymer solutions were injected during the first part of the pilot. However, later analysis revealed that sweep efficiency could be improved significantly using polymer solutions up to 160 cp. Although injection was done at pressures below what was believed to be the formation parting pressure, injectivity data from several water injection cycles shows that partition of the formation followed by partial sustenance of the fracture did occur. Analysis of produced water salinities, polymer and tracer concentrations, water/oil ratios (WOR), and inter-well pressure responses all indicated that severe channeling (i.e., through fracture-like features) did not occur. Instead, analysis of the project response indicated that (1) sweep could benefit from injecting more viscous polymer solutions, (2) injectivity for more viscous polymers would not be a problem because of controlled (i.e., not detrimental) fracture extension, and (3) oil production rates could be enhanced (without sacrificing WOR) by increasing injection rates. Consequently, these ideas are currently being field tested in our project. This paper details results to date for this polymer pilot.
In a previous publication we introduced a methodology to assist in choosing between Enhanced Oil recovery (EOR) and infill well drilling (SPE 143300). Operating companies are often reluctant to use EOR techniques when they have the option of infill well drilling instead. Reasons for this include how operating companies assess and manage risk and uncertainties. The methodology developed includes performing reservoir calculations to evaluate additional recovery using both techniques, and then using data generated as input to economic analysis. In the previous work, polymer flooding for 10 years after two years of waterflooding was studied using a synthetic reservoir model. The technique involved running a range of reservoir simulation scenarios to test possible recovery outcomes; these outcomes then provide input data that will be used in the probabilistic economic evaluation tool to be introduced as a follow up in this paper.
This current paper presents the results of the impact of operational factors, such as delaying the start of polymer flooding. This involves assessing the best possible timing for polymer injection to achieve optimal economics. This type of assessment is possible because the economic model developed and presented here allows input from multiple reservoir simulation sensitivity calculations. Monte Carlo Simulation (MCS) is then performed to establish confidence in the method, and test economic uncertainties and the risks associated with implementation of polymer flooding. Defining variables with a probability distribution can establish more precisely the economic value of the polymer flooding project. The analysis of uncertainty involves measuring the degree to which input contributes to uncertainty in the output.
MCS is a statistics based analysis tool that yields probability impact on Net Present Value (NPV) of the key operational parameters included in the project (oil, water and polymer production and injection costs, polymer concentration, timing, etc.) and various economic factors (oil price, polymer cost, etc).
A new polymer based gel system has been developed to address the excessive water production problem in fractured unconventional gas wells. Currently available polymer based water shut-off agents are unsuitable for treating high temperature hydraulically-fractured tight gas and shale reservoirs, where some fractures connect to water rich zones. The new gel developed is a low-concentration, low-viscosity delayed-crosslink polymeric gel system and is a significant improvement over traditional flowing gels used for fracture water shutoff in conventional reservoirs. The gel uses high molecular weight hydrolyzed polyacrylamide (HPAM) at low concentrations with a delayed organic crosslinker that is more environmentally benign, provides much longer gelation time (up to several days at temperatures well above 100 °C) and stronger final gels than comparable polymer loadings with chromium carboxylate crosslinkers. Results indicate that gelant with a few tens of centipoise viscosity can have gelation delayed to 12 hours or longer at temperatures of 100 °C and higher. Gels prepared with 4000 to 7000 ppm of HPAM and Polyethylenimine (PEI) were significantly stronger than those prepared with the Chromium(III) Acetate crosslinker for the same HPAM concentrations. This new gel system allows low-pressure extrusion of gelant into narrow-aperture fractures. The system is especially promising for deeper, hotter formations where rapid pressure buildup or gel instability prevents the use of current flowing gel systems. The gelant can be pumped with low pressures due to low concentration of polymer and delayed gelation to effectively seal problem water zones thereby reducing operational costs and increasing recovery. By impeding water production, the gel system developed here can be used to delay water loading and subsequent premature abandonment (or installation of expensive equipment), thereby extending life and reserves of unconventional gas wells. Potential applications include the Barnett Shale, where 15 percent of wells produce more water than injected during drilling and stimulation, presumably due to hydraulic fracture growth into underlying water zones.|