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.
Installing an inappropriate or poorly specified ESP leads to lost production, short runlives, and ultimately higher production costs. With the growth in ESP-produced unconventional wells, appropriate ESP design becomes more challenging due to divergent HP and head requirement at initial production versus the depleted well at end of life. ESP design is typically performed by the ESP vendors (often with less than complete design data), reviewed by the production engineer, and then equipment selected and installed. Intended for any oilfield technical professional who needs a general understanding of Electrical Submersible Pumps, this one-day introductory class provides a practical overview with an emphasis on understanding the system configuration and theory of operation. Significant class time will be spent on understanding each ESP component’s contribution to the overall system.
This advanced course is intended for artificial lift and production professionals currently working with or managing ESPs. The teardown (or dismantle) of the ESP is the final phase of an ESP’s operation, but one that can give the most information on how the ESP performed during its life. Additionally, and maybe more importantly, the teardown and subsequent analysis can tell you why it failed. This key step is not simply taking each component apart, the ESP must be disassembled in a particular order, carefully inspecting for specific failure modes at each step, and, that order may vary with conditions and circumstances. Intended for any oilfield technical professional who needs a general understanding of Electrical Submersible Pumps, this one-day introductory class provides a practical overview with an emphasis on understanding the system configuration and theory of operation.
Temizel, Cenk (Aera Energy) | Canbaz, Celal Hakan (Ege University) | Palabiyik, Yildiray (Istanbul Technical University) | Putra, Dike (Rafflesia Energy) | Asena, Ahmet (Turkish Petroleum Corp.) | Ranjith, Rahul (Far Technologies) | Jongkittinarukorn, Kittiphong (Chulalongkorn University)
Smart field technologies offer outstanding capabilities that increase the efficiency of the oil and gas fields by means of saving time and energy as far as the technologies employed and workforce concerned given that the technology applied is economic for the field of concern. Despite significant acceptance of smart field concept in the industry, there is still ambiguity not only on the incremental benefits but also the criteria and conditions of applicability technical and economic-wise. This study outlines the past, present and the dynamics of the smart oilfield concept, the techniques and methods it bears and employs, technical challenges in the application while addressing the concerns of the oil and gas industry professionals on the use of such technologies in a comprehensive way.
History of smart/intelligent oilfield development, types of technologies used currently in it and those imbibed from other industries are comprehensively reviewed in this paper. In addition, this review takes into account the robustness, applicability and incremental benefits these technologie bring to different types of oilfields under current economic conditions. Real field applications are illustrated with applications in different parts of the world with challenges, advantages and drawbacks discussed and summarized that lead to conclusions on the criteria of application of smart field technologies in an individual field.
Intelligent or Smart field concept has proven itself as a promising area and found vast amount of application in oil and gas fields throughout the world. The key in smart oilfield applications is the suitability of an individual case for such technology in terms of technical and economic aspects. This study outlines the key criteria in the success of smart oilfield applications in a given field that will serve for the future decisions as a comprehensive and collective review of all the aspects of the employed techniques and their usability in specific cases.
Even though there are publications on certain examples of smart oilfield technologies, a comprehensive review that not only outlines all the key elements in one study but also deducts lessons from the real field applications that will shed light on the utilization of the methods in the future applications has been missing, this study will fill this gap.
Zhu, Haiyan (Chengdu University of Technology) | Zhao, Ya-Pu (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation) | Feng, Yongcun (Institute of Mechanics, Chinese Academy of Sciences) | Wang, Haowei (Institute of Mechanics, Chinese Academy of Sciences) | Zhang, Liaoyuan (University of Chinese Academy of Sciences) | McLennan, John D. (University of Texas at Austin)
Haiyan Zhu, Chengdu University of Technology, State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, and Institute of Mechanics, Chinese Academy of Sciences; Ya-Pu Zhao, Institute of Mechanics, Chinese Academy of Sciences and University of Chinese Academy of Sciences; Yongcun Feng, University of Texas at Austin; Haowei Wang, Southwest Petroleum University; Liaoyuan Zhang, Sinopec Shengli Oilfield Company; and John D. McLennan, University of Utah Summary Channel fracturing acknowledges that there will be local concentrations of proppant that generate high-conductivity channel networks within a hydraulic fracture. These concentrations of proppant form pillars that maintain aperture. The mechanical properties of these proppant pillars and the reservoir rock are important factors affecting conductivity. In this paper, the nonlinear stress/strain relationship of proppant pillars is first determined using experimental results. A predictive model for fracture width and conductivity is developed when unpropped, highly conductive channels are generated during the stimulation. This model considers the combined effects of pillar and fracture-surface deformation, as well as proppant embedment. The influence of the geomechanical parameters related to the formation and the operational parameters of the stimulation are analyzed using the proposed model. The results of this work indicate the following: 1. Proppant pillars clearly exhibit compaction in response to applied closure stress, and the resulting axial and radial deformation should not be ignored in the prediction of fracture conductivity. Introduction In conventional hydraulic-fracturing treatments, it is presumed that proppant is distributed uniformly in the fracturing fluid and generates a uniform proppant pack in the fracture (left-hand side of Figure 1). The propped fracture serves as a high-conductivity channel facilitating fluid flow from the reservoir to the well. Channel fracturing is a new fracturing concept, and replaces a nominally homogeneous proppant pack in the fracture with a heterogeneous structure containing a network of open channels (Figure 1, right) (Gillard et al. 2010). This channel-like structure is achieved by using fiber-laden fluids or self-aggregating proppant together with a pulsed-pumping strategy. In channel fracturing, the interaction between the proppant and fracture surfaces is a "point" contact, in contrast to the "surface" contact assumed to exist in conventional fracturing.
Due to the decrease in commodity prices in a constantly dynamic environment, there has been a constant urge to maximize benefits and attain value from limited resources. Traditional empirical and numerical simulation techniques have failed to provide comprehensive optimized solutions in little time. Coupled with the immense volumes of data generated on a daily basis, a solution to tackle industry challenges became imminent. Various expert opinion fraught with bias has posed extra challenges to obtain timely cost-effective solutions. Data Analytics has provided substantial contributions in several sectors. However, its value has not been captured in the Oil and Gas industry. This paper presents a review of various Machine Learning applications in exploration, completions, production operations to date. An overview of data-driven workflows in the fields of electric submersible pump (ESP) failure and shutdown prediction, reservoir databases' analysis, reduction of subsurface uncertainty, EOR decisions using scarce data, improved oil recovery estimation, production impact assessment, horizontal completion, fracturing techniques, production optimization in unconventional reservoirs, production management, and field surveillance, is presented. The review attempts to shed light on the benefits and applications of multiple challenges faced on a daily basis by scientists, field personnel, and engineers to help solve and optimize the industry's multifaceted data-intense challenges.
Barnes, Julian R. (Shell Global Solutions International) | van Batenburg, Diederik W. (Shell Global Solutions International) | Faber, M. J. (Shell Global Solutions International) | van Rijn, Carl H. T. (Shell Global Solutions International) | Geib, Sonja (Shell Global Solutions International) | van Kuijk, Sjoerd R. (Shell Global Solutions International) | Perez Regalado, David (Shell Global Solutions International) | King, Tim E. (Shell Global Solutions US) | Doll, Mike J. (Shell Global Solutions US) | Crom, Lori E. (Shell Global Solutions US)
Alkaline/surfactant/polymer (ASP) flooding is an enhanced-oil-recovery (EOR) technique that involves the injection of a solution of surfactant, alkali, and polymer into an oil reservoir to mobilize and produce the remaining oil. There are several pattern-flood pilots in progress or that will soon be executed to evaluate ASP at a scale relevant to commercial-scale application. The quantities of surfactants needed for these pilots and potential future commercial-scale applications are large (hundreds to thousands of tonnes) and necessitate large-scale manufacture using existing processes and plants for the different manufacturing steps. These operate under slightly different process conditions than those used to make the smaller quantity (50 to 400 kg) of the reference blend used to design the formulation in the laboratory. The upscaling of the surfactant production itself is an essential step to enable field-scale implementation of ASP. To ensure and control the quality of the surfactants produced for pilots with Shell interests, a stage-gated quality assurance/quality control (QA/QC) program was designed and executed. The application of the QA/QC process for a high- and a low-active-matter surfactant-blend concentrate (approximately 60% and 20% active, respectively) is used to illustrate the process.
The early definition of the QA/QC program provided a framework with clearly defined stages for upscaling from laboratory- to large-scale production. The definition of analytical and performance-based laboratory experiments with upfront-defined specifications (minimum and maximum values) and repeatability allowed for clear, unambiguous decisions. Correlations between composition and performance that were developed dependent on pilot-scale production were essential to assure the performance of the larger-scale production. Corefloods, used as the ultimate performance check, showed virtually identical performance for pilot-scale prepared surfactants and surfactants from different large-scale batches.
The paper illustrates that consistent industrial-scale production of surfactants for application in chemical EOR (CEOR) is feasible. To ensure the quality of such surfactant requires a detailed QA/QC program. The successful execution of the QA/QC program for the surfactants for the pattern pilots ensures that the produced large-scale surfactant blend performs as the reference blend used to design the formulation.
Al-Murayri, Mohammed T. (Kuwait Oil Company) | Kamal, Dawoud S. (Kuwait Oil Company) | Al-Mayyan, Haya (Kuwait Oil Company) | Shahin, Gordon T. (Shell) | Shukla, Shunahshep R. (Shell) | Ten Berge, Anke B.G.M. (Shell)
Following encouraging results from laboratory experiments, simulation studies and a one-spot EOR pilot for the Raudhatain Zubair (RAZU) reservoir in Kuwait, a multi-well pilot is planned in the near future. A combination of high temperature (90°C), in-situ brine salinity (>250,000 ppm) and divalent ion concentration (>20,000 ppm) make implementation of Alkaline Surfactant Polymer (ASP) flooding in RAZU quite challenging. The presence of a ‘Tar Mat’ interval in the pilot area further complicates pilot design. This paper outlines some of the risk mitigation measures for a successful ASP pilot.
Laboratory experiments were performed to evaluate different polymers for improved thermal stability and to obviate the risk of polymer precipitation at the producers. Based on long-term thermal stability studies and producer scaling considerations, HPAM/ATBS based polymer was chosen over HPAM -based polymer. The original formulation which was used in the one-spot EOR pilot required 3.5% co-solvent to overcome surfactant separation at optimal salinity. Several alternative alcohols were tested and finally an appropriate co-solvent that gave adequate performance at 1.5 wt% was selected to reduce cost and logistical requirements. Additionally, optimization experiments were conducted to de-risk emulsification potential of produced oil by reducing the concentration of the injected surfactants. Finally, experiments were carried out to characterize the nature of the hydrocarbon and rock in the ‘Tar Mat’ interval to evaluate the risk versus reward of perforating it in the pilot area.
This is the first time, to our knowledge, that ASP injection is being considered in a reservoir in such a harsh environment due to combination of high temperature, salinity and divalent ion concentration in formation brine. The presence of a ‘Tar Mat’ interval further complicates pilot design. The successful execution of this pilot will push the envelope of ASP deployment in other challenging reservoirs worldwide.
Polymer flooding is a mature Enhanced Oil Recovery process which is used worldwide in many large- scale field expansions. Encouraged by these positive results, operators are still looking at applying the process in new fields even in the context of low oil prices and are evaluating its feasibility in more challenging reservoir conditions: high salinity, high hardness and high temperature. Several solutions have been proposed to overcome the limitations of the conventional hydrolyzed polyacrylamide (HPAM) in these types of challenging environments: biopolymers such as xanthan or scleroglucan, associative polymers, or co- or ter-polymers combining acrylamide with monomers such as ATBS or NVP. Each of these solutions has its advantages and disadvantages, which are not always clear for practicing engineers. Moreover, it is always interesting to study past field experience to confront theory with practice. This is what this paper proposes to do.
The paper will first review the limits of conventional HPAM and other polymers that have been proposed for more challenging reservoir conditions. But more than that, it will focus on the field experience with each of these products to establish some practical guidelines for the selection of polymers depending on the reservoir and fluid characteristics.
One first result of this review is that the limits of conventional HPAM may not be as low as usually expected. Biopolymers appear very sensitive to biodegradation and their success in the field has been limited. Associative polymers appear better suited to near-wellbore conformance control than to displacement processes and some of the new co and ter-polymers are currently being field tested with some measure of success. It appears that the main challenge lies with high temperature rather than high salinity; some field projects are currently ongoing in high salinity (200 g/L) and hardness.
The paper will help set the current limits for polymer flooding in terms of temperature, salinity and hardness based on laboratory work and field experience. This will prove a useful guide for practicing engineers looking to pilot polymer injection in challenging reservoir conditions.