Hwang, Jongsoo (The University of Texas Austin) | Sharma, Mukul (The University of Texas Austin) | Chiotoroiu, Maria-Magdalena (OMV Exploration & Production GmbH) | Clemens, Torsten (OMV Exploration & Production GmbH)
Several field cases reported that polymer injection in a horizontal well is a viable solution to increase oil recovery. The injectivity, however, may vary significantly depending on fluid, reservoir, and geomechanical conditions. Polymer injection without understanding these factors may lead to injectivity impairment, unswept zones, and fractures undesirable for the sweep. In this paper, we present a comprehensive viscoelastic polymer injectivity model for vertical and horizontal wells.
We developed a simulator to compute viscoelastic polymer injectivity by accounting for particle filtration, thermo-poro-elastic stress changes, fracture propagation, flow distributions among multiple layers, and viscoelastic polymer rheology. Simulation results clearly show that the contribution of shear-thickening characteristics on the polymer can have a large impact in un-fractured wells but have a much smaller impact in fractured injectors. The impact of geomechanical stress changes and subsequent induced fractures are also highlighted.
The model was then applied for a field case study to identify critical aspects needed to maintain high injectivity. Two field case wells are presented where water and viscoelastic polymer are injected for a vertical well and a horizontal well accessing the multi-layered reservoir respectively. For the two injectors, water was injected initially, and then HPAM polymer solution followed to improve oil recovery. Fracture growth and injection into a long horizontal lateral are the key factors that allowed the operator to maintain injectivity by reducing the Darcy velocity, shear rate, and shear-thickening zone. For a horizontal well, operating conditions are also identified by simulations to ensure matrix injection, which is the desired conformance and sweep improvement option.
Green fields today mostly can be regarded as marginal fields and successfully developed. It covers the complete assessment of the oil and gas recovery potential from reservoir structure and formation evaluation, oil and gas reserve mapping, their uncertainties and risks management, feasible reservoir fluid depletion approaches, and to the construction of integrated production systems for cost effective development of the green fields. Depth conversion of time interpretations is a basic skill set for interpreters. There is no single methodology that is optimal for all cases. Next, appropriate depth methods will be presented. Depth imaging should be considered an integral component of interpretation. If the results derived from depth imaging are intended to mitigate risk, the interpreter must actively guide the process.
Schumi, Bettina (OMV E&P) | Clemens, Torsten (OMV E&P) | Wegner, Jonas (HOT Microfluidics) | Ganzer, Leonhard (Clausthal University of Technology) | Kaiser, Anton (Clariant) | Hincapie, Rafael E. (OMV E&P) | Leitenmüller, Verena (Montan University Leoben)
Chemical Enhanced Oil Recovery leads to substantial incremental costs over waterflooding of oil reservoirs. Reservoirs containing oil with a high Total Acid Number (TAN) could be produced by injection of alkali. Alkali might lead to generation of soaps and emulsify the oil. However, the generated emulsions are not always stable.
Phase experiments are used to determine the initial amount of emulsions generated and their stability if measured over time. Based on the phase experiments, the minimum concentration of alkali can be determined and the concentration of alkali above which no significant increase in formation of initial emulsions is observed.
Micro-model experiments are performed to investigate the effects on pore scale. For injection of alkali into high TAN number oils, mobilization of residual oil after waterflooding is seen. The oil mobilization is due to breaking-up of oil ganglia or movement of elongated ganglia through the porous medium. As the oil is depleting in surface active components, residual oil saturation is left behind either as isolated ganglia or in down-gradient of grains.
Simultaneous injection of alkali and polymers leads to higher incremental oil production in the micro-models owing to larger pressure drops over the oil ganglia and more effective mobilization accordingly.
Core flood tests confirm the micro-model experiments and additional data are derived from these tests. Alkali co-solvent polymer injection leads to the highest incremental oil recovery of the chemical agents which is difficult to differentiate in micro-model experiments. The polymer adsorption is substantially reduced if alkali is injected with polymers compared with polymer injection only. The reason is the effect of the pH on the polymers. As in the micro-models, the incremental oil recovery is also higher for alkali polymer injection than with alkali injection only.
To evaluate the incremental operating costs of the chemical agents, Equivalent Utility Factors (EqUF) are calculated. The EqUF takes the costs of the various chemicals into account. The lowest EqUF and hence lowest chemical incremental OPEX are incurred by injection of Na2CO3, however, the highest incremental recovery factor is seen with alkali co-solvent polymer injection. It should be noted that the incremental oil recovery owing to macroscopic sweep efficiency improvement by polymer needs to be taken into account to assess the efficiency of the chemical agents.
The aim of this paper is to compare the performance of three horizontal infill wells in a mature field, of which one is completed with autonomous inflow control devices (AICDs). The analytic results are based on the comparison of oil production rates; water cut development and water-oil ratio plots of the wells. All the wells in this study are producing from the same homogeneous sandstone reservoir.
Two of the horizontal infill wells are targeting attic oil in an area with low risk of gas production of which one of these wells is completed with slotted liners and the other with AICDs. Both are artificially lifted with high rate electrical submersible pumps (ESPs). The third horizontal well was placed in an area with higher gas saturation, where a completion with casing, cementation and perforation was used. The performance of the horizontal wells is compared against each other.
The use of active geo-steering successfully supported the well placement into the "sweet spot" of the reservoir due to real-time well path adjustments.
It was found that the AICDs choke back a high amount of fluid and keep the water cut at a stable plateau level. This observation underlines the key benefit of using AICDs as when comparing to the other producing wells without AICDs, the water cut is steadily increasing.
Therefore the use of AICDs is a real option for horizontal well completion.
This paper will be useful to those who are in a phase of early well planning, e.g. in a field (re-)development project and have to select the best well concept (e.g. slotted liner vs. AICDs). AICDs have proven their value even in a super-mature oil field by improving production. Further advantages and challenges during operation are discussed in this paper.
One of the main uncertainties when designing polymer floods is the polymer injectivity, an important parameter that can affect the economics of the process. Reservoir simulation can be used to forecast injectivity, but the process is not straightforward and can be affected by grid size and other factors. Analytical methods are also available for that purpose, but they are considered too simplistic to deal with realistic reservoir conditions. The aim of this paper is to show that this is not the case and that simple analytical tools can be accurate and of great help to predict or history match polymer injectivity.
The analytical method has been developed by Lake in his classical textbook on Enhanced Oil Recovery, but few applications are documented in the literature. This paper will review the method and corresponding equations before presenting several actual field cases of injectivity in polymer flood pilots or tests from several countries that have been matched analytically.
Although it has not been used very often, the method has been found to give very good results in most of the field cases tested in a variety of situations; these cases will be presented along with recommendations on how to apply the method and a discussion of the results. Sensitivities to the various parameters will also be presented. Once the equations are programmed in a spreadsheet, the matching process takes only a few minutes and it is easy to run various scenarios and sensitivities.
Polymer injectivity remains one of the less understood and less predictable aspects of polymer flood projects. This paper will encourage engineers who are planning such projects to use simple yet accurate analytical tools before embarking in more complex and time-consuming reservoir simulations.
Chiotoroiu, Maria-Magdalena (OMV E&P) | Clemens, Torsten (OMV E&P) | Zechner, Markus (OMV E&P/Stanford University) | Hwang, Jongsoo (University of Texas) | Sharma, Mukul M. (University of Texas) | Thiele, Marco (Streamsim/Stanford University)
Waterflooding can lead to substantial incremental oil production. Implementation of water injection projects requires the project to fit into the risk (defined here as negative outcomes relative to defined project objectives) and uncertainty (defined here as inability to estimate a value precisely) a company is willing to take.
One of the key risks for water injection into a shallow reservoir is injection induced fractures extending into the caprock. If this risk is seen as "Intolerable" in an As Low As Reasonable Practicable (ALARP) analysis a decision may be made to not proceed with the project., In this study we evaluated caprock integrity by conducting simulations of long-term water injection that include the effects of formation damage caused by internal/external plugging, geomechanical stress changes and fracture propagation in the sand and bounding shale.
The risk of fracture growth into the caprock was assessed by conducting Monte-Carlo simulations considering a set of modelling parameters each associated with an uncertainty range. This allowed us to identify the range of operating parameters where the risk of fracture height growth was acceptable. Our simulations also allowed us to identify important factors that impact caprock integrity. To cover the uncertainty in geomechanical reservoir evaluation, the operating envelope is identified such that the risk of the caprock integrity is reduced. This requires introducing a limit for the Bottom Hole Pressure (BHP) including a safety margin.
The limit of the BHP is then used as a constraint in the uncertainty analysis of water injectivity. The uncertainty analysis should cover the various development options, the parametrisation of the model, sampling from the distribution of parameters and distance-based Generalized Sensitivity Analysis (dGSA) as well as probabilistic representation of the results.
The dGSA can be used to determine which parameter has a strong impact on the BHP and hence the project and should be measured if warranted by a Value of Information analysis.
The final development option to be chosen depends on a traditional NPV analysis.
Nagar, Ankesh (Cairn Oil & Gas – Vedanta Limited) | Dangwal, Gaurav (Cairn Oil & Gas – Vedanta Limited) | Maniar, Chintan (Cairn Oil & Gas – Vedanta Limited) | Bhad, Nitin (Cairn Oil & Gas – Vedanta Limited) | Goyal, Ishank (Cairn Oil & Gas – Vedanta Limited) | Pandey, Nimish (Cairn Oil & Gas – Vedanta Limited) | Parashar, Arunabh (Cairn Oil & Gas – Vedanta Limited) | Tiwari, Shobhit (Cairn Oil & Gas – Vedanta Limited)
The Mangala, Aishwaya & Bhagyam (MBA) fields are the largest discovered group of oil fields in Barmer Basin, Rajasthan, India. The fields contain medium gravity viscous crude (10-40cp) in high permeability (1-5 Darcy) sands. The fields have undergone pattern as well as peripheral water injection. In order to overcome adverse mobility ratio and improve sweep efficiency thereby increasing oil recovery, chemical EOR has been evaluated for implementation in these fields. The potential benefits from chemical enhanced oil recovery (EOR) had been recognized from early in the field development. Polymer flooding was identified for early implementation, which would be followed by stage wise implementation of Alkaline-Surfactant-Polymer (ASP) injection in fields like Mangala. Since the commencement of polymer injection, the Mangala field polymer injectors have displayed multiple injectivity issues. In addition, the Aishwarya and Bhagyam fields are dealing with low Void Replacement Ratios (VRR) for their ongoing water injection, which if not rectified could adversely affect recovery. While various types of injector stimulations are being used, injectivity increases are short lived. A new technique termed as ‘Sand Scouring’ has been successfully applied resuting in sustainable injectivity gains.
The technique involves pumping creating a small fracture with a pad injected above fracturing pressure and then scouring the fracture face with low concentration 20/40 sand slugs in range of 0.5 to 1 PPA 20/40. The treatments are pumped at the highest achievable rates with the available pumping equipment within the completion pressure limitations. Based upon the available tankage, the scheduled is designed such that pumping of a fixed volume of sand stage, a quick shut-down allows for mixing the next stage of slurry. The pumping schedule and a ‘scouring’ intent is deliberately designed to avoid requirement of fracturing equipment, related cleanout equipment and resulting costs. The challenge of conformance is addressed by designing the pumping schedule to incorporate stages of particulate diverters and validated using pre and post injection logging surveys. .
Sand scouring jobs in 16 wells have been conducted across Mangala, Bhagyam & Aishwarya injectors. Out of thesewells, 9 wells had zero injectivity while the other 7 required both injectivity and conformance improvement. Most of the treated wells resulted in multifold improvement of injectivity as compared to their prior injection parameters. Sand scouring resulted in sustained injection performance when compared with prior conventional methods of stimulation. Injectivity improvements from sand scouring lasted for an average of 3 months days as compared to 14 days for the conventional stimulations. Sand scouring evolution, design, results and plans for future improvement are all discussed in this paper.
Alkinani, Husam H. (Missouri University of Science and Technology) | Al-Hameedi, Abo Taleb T. (Missouri University of Science and Technology) | Dunn-Norman, Shari (Missouri University of Science and Technology) | Alsaba, Mortadha T. (Australian College of Kuwait) | Amer, Ahmed S. (Newpark Technology Center/ Newpark Drilling Fluids)
As oil prices are fluctuating, decision makers are challenged to make the "best" decisions for field's developments. Decision Tree Analysis (DTA) can help decision makers to make the "best" decisions. DTA focuses on managerial decisions, such as whether to do workover or not, whether the additional information will be valuable or not. The aim of this work is to review the applications of DTA in petroleum engineering and provide a clear methodology on how to apply DTA for any petroleum engineering application.
The combination of Expected Monetary Value (EMV) and DTA is one of the most common methods used in the decision-making process. If EMV is positive, the decision is considered to be feasible. However, that doesn't mean the decision will be successful at all times. It simply means that if a similar decision is made for a larger number of cases, the decision will be successful. DTA will account for the uncertainty in the probability. A good number of papers about the applications of DTA in petroleum engineering were read and summarized into three categories. Also, a clear methodology on how to apply the DTA for any petroleum engineering application was established.
After reading and summarizing a good number of papers and case histories about the applications of DTA in petroleum engineering, it was concluded that the applications can be classified into three main categories; applications of DTA and EMV for the whole oil and gas prospect projects, applications of DTA and EMV for a specific operation or development, applications of DTA, EMV, Monte Carlo simulations, and other methods to assess the value of information. These applications were summarized into tables.
In addition, a clear methodology accomplished by a flowchart that explains how to successfully apply the EMV and DTA for any petroleum engineering application was provided. The method consists of three main steps: 1) how many scenarios need to be considered and what are they 2) collection of the required data 3) use the visual tool (DTA) or programming to find EMV. Each of the previous steps has its own challenges, thus these challenges were addressed and the solutions to overcome the challenges were provided. Finally, practical guidelines have were developed that when used with the accompanying flow chart will serve as a quick reference to apply the DTA for any petroleum engineering application.
As the petroleum engineering applications becoming more complicated nowadays, accomplished by the oil prices fluctuations, the decision-making processes becoming more difficult. The DTA is a very important tool for the decision makers to make the "best" decision. This paper provides a clear methodology on how to successfully apply the DTA which can serve as a reference for any future DTA applications in petroleum engineering.
Siv Marie Åsen, UiS, IRIS, and The National IOR Centre of Norway; Arne Stavland and Daniel Strand, IRIS; and Aksel Hiorth, UiS, IRIS, and The National IOR Centre of Norway Summary In this work, we examine the common understanding that mechanical degradation of polymers takes place at the rock surface or within the first few millimeters of the rock. The effect of core length on mechanical degradation of synthetic enhanced-oil-recovery (EOR) polymers was investigated. We constructed a novel experimental setup for studying mechanical degradation at different flow velocities as a function of distances traveled. The setup enabled us to evaluate degradation in serial mounted core segments of 3, 5, 8, and 13 cm individually or combined. By recycling, we could also evaluate degradation at effective distances up to 20 m. Experiments were performed with two different polymers [high-molecular-weight (MW) hydrolyzed polyacrylamide (HPAM) and low-MW acrylamide tertiary butyl sulfonic acid (ATBS)] in two different brines [0.5% NaCl and synthetic seawater (SSW)]. In the linear flow at high shear rates, we observed a decline in degradation rate with distance traveled. Even after 20 m, some degradation occurred. However, the observed degradation was associated with high pressure gradients of 100 bar/m, which at field scale is not realistic. It is possible that oxidative degradation played a significant role during our experiments, where the polymer was cycled many times through a core.
Steineder, Dominik (OMV Exploration and Production) | Clemens, Torsten (OMV Exploration and Production) | Osivandi, Keyvan (OMV Exploration and Production) | Thiele, Marco R. (Streamsim Technology and Stanford University)
Polymer injection might lead to incremental oil recovery and increase the value of an asset. Several steps must be taken to mature a polymer-injection project. The field needs to be screened for applicability of polymer injection, laboratory experiments have to be performed, and a pilot project might be required before field implementation.
The decision to perform a pilot project can be dependent on a value-of-information (VOI) calculation. The VOI can be derived by performing a work flow that captures the effects of the range of geological scenarios, as well as dynamic and polymer parameters, on incremental net present value (NPV). The result of the work flow is a cumulative distribution function (CDF) of NPV linked to prior distributions of model parameters and potential observables from the polymer-injection pilot.
The effect of various parameters on the CDF of the fieldwide NPV can be analyzed and in turn used to decide which measurements from the pilot have a strong sensitivity on the NPV CDF, and are thus informative. In the case shown here, the water-cut reduction in the pilot area has a strong effect on the NPV CDF of the polymer-injection field implementation. To extract maximum information, the response of the pilot for water-cut reduction needs to be optimized under uncertainty.
To calculate the VOI, the expected-monetary-value (EMV) difference of a decision tree with and without the pilot can be used if the decision maker (DM) is risk neutral. However, if the DM requires hurdle values through a probability of economic success (PES), value functions (VFs) and decision weights according to the prospect theory should be used. Applying risk hurdles requires a consistent use of VFs and decision weights for calculating VOI and the probability of maturation (POM) of projects.
The methodology was applied to assess the VOI for a horizontal-well pilot in the ninth Tortonian Horizon (9TH) Reservoir in Austria for a risk-averse DM. The operating parameters (polymer concentration and water injection) were chosen such that the watercut reduction, which was the most influential parameter of the polymer pilot on the field NPV CDF, was maximized.