Africa (Sub-Sahara) Equatorial Guinea's Ministry of Mines and Hydrocarbons has notified Ophir Energy that it will not gain an extension for the offshore Block R license. The block contains the deepwater Fortuna gas discovery. Ophir had been seeking to develop the gas using a Golar-converted floating liquefied-natural-gas (LNG) vessel, but failed to secure sufficient financial backing for the project. Front-end engineering design had begun in July 2015. Targeted production was approximately 330 MMcf/D, with a plateau of 30 years. Located approximately 140 km west of Bioko Island, the Fortuna project was to see development of six commercial discoveries in a phased manner.
Temizel, Cenk (Aera Energy) | Balaji, Karthik (University of North Dakota) | Canbaz, Celal Hakan (Ege University) | Palabiyik, Yildiray (Istanbul Technical University) | Moreno, Raul (Smart Recovery) | Rabiei, Minou (University of North Dakota) | Zhou, Zifu (University of North Dakota) | Ranjith, Rahul (Far Technologies)
Due to complex characteristics of shale reservoirs, data-driven techniques offer fast and practical solutions in optimization and better management of shale assets. Developments in data-driven techniques enable robust analysis of not only the primary depletion mechanisms, but also the enhanced oil recovery in unconventionals such as natural gas injection. This study provides a comprehensive background on application of data-driven methods in oil and gas industry, the process, methodology and learnings along with examples of data-driven analysis of natural gas injection in shale oil reservoirs through the use of publicly-available data.
Data is obtained and organized. Patterns in production data are analyzed using data-driven methods to understand key parameters in the recovery process as well as the optimum operational strategies to improve recovery. The complete process is illustrated step-by-step for clarity and to serve as a practical guide for readers. This study also provides information on what other alternative physics-based evaluation methods will be able to offer in the current conditions of data availability and the understanding of physics of recovery in shale oil assets together with the comparison of outcomes of those methods with respect to the data-driven methods. Thereby, a thorough comparison of physics-based and data-driven methods, their advantages, drawbacks and challenges are provided.
It has been observed that data organization and filtering takes significant time before application of the actual data-driven method, yet data-driven methods serve as a practical solution in fields that are mature enough to bear data for analysis as long as the methodology is carefully applied. The advantages, challenges and associated risks of using data-driven methods are also included. The results of comparison between physics-based methods and data-driven methods illustrate the advantages and disadvantages of each method while providing the differences in evaluation and outcome along with a guideline for when to use what kind of strategy and evaluation in an asset.
A comprehensive understanding of the interactions between key components of the formation and the way various elements of an EOR process impact these interactions, is of paramount importance. Among the few existing studies on natural gas injection in shale oil with the use of data-driven methods in oil and gas industry include a comparative approach including the physics-based methods but lack the interrelationship between physics-based and data-driven methods as a complementary and a competitor within the era of rise of unconventionals. This study closes the gap and serves as an up-to-date reference for industry professionals.
Huang, Hai (Xi'an Shiyou University, Shaanxi Key Laboratory of Advanced Stimulation Technology for Oil & Gas Reservoirs) | Babadagli, Tayfun (University of Alberta) | Chen, Xin (University of Alberta) | Li, Huazhou (University of Alberta)
Tight sands are abundant in nanopores leading to a high capillary pressure and normally a low fluid injectivity. As such, spontaneous imbibition might be an effective mechanism for improving oil recovery from tight sands after fracturing. The chemical agents added to the injected water can alter the interfacial properties, which could help further enhance the oil recovery by spontaneous imbibition. This study explores the possibility of using novel chemicals to enhance oil recovery from tight sands via spontaneous imbibition. We experimentally examine the effects of more than ten different chemical agents on spontaneous imbibition, including a cationic surfactant (C12TAB), two anionic surfactants (O242 and O342), an ionic liquid (BMMIM BF4), a high pH solution (NaBO2), and a series of house-made deep eutectic solvents (DES3-7, 9, 11 and 14). Experimental results indicate that the ionic liquid and cationic surfactant used in this study are detrimental to spontaneous imbibition and decrease the oil recovery from tight sands. The high pH NaBO2 solution does not demonstrate significant effect on improving oil recovery, even though it significantly reduces oil-water interfacial tension (IFT). The anionic surfactants (O242 and O342) are effective in enhancing oil recovery from tight sands through oil-water IFT reduction and emulsification effects. The DESs drive the rock surface to be more water-wet and a specific formulation (DES9) leads to much improvement on oil recovery under counter-current imbibition condition. This preliminary study would provide some knowledge about how to optimize the selection of chemicals for improving oil recovery from tight reservoirs.
Review our data policy for information about these graphics and how they may be used. Integrated Historical Data Workflow: Maximizing the Value of a Mature Asset Industry studies show that mature fields currently account for over 70% of the world’s oil and gas production. Increasing production rates and ultimate recovery in these fields in order to maintain profitable operations, without increasing costs, is a common challenge. This lecture addresses techniques to extract maximum value from historical production data using quick workflows based on common sense. Extensive in-depth reservoir studies are obviously very valuable, but not all situations require these, particularly in the case of brown fields where the cost of the study may outweigh the benefits of the resulting recommendations. This lecture presents workflows based on Continuous Improvement/LEAN methodology which are flexible enough to apply to any mature asset for short and long term planning. A well published, low ...
Hashim Noori, Wildan (Istanbul Technical University) | Cinar, Murat (Istanbul Technical University) | Salehian, Mohammad (Istanbul Technical University) | Alkouh, Ahmad (College of Technological Studies)
Steam injection is one of the well-known thermal recovery processes that has been extensively applied to heavy oil reservoirs. Several efforts have been made to understand theoretical and practical aspects of steam injection and alkali flooding. However, the detailed information about the performance of steam-alkali flooding in field applications has not been deeply addressed yet. In this sense, in order to shed light on the background and applications in this area, this study comparatively investigates the efficiency of different strategies of pure steam injection and cyclic steam-alkali flooding in Bati Raman oil field, Turkey.
Three experiments were conducted to evaluate the advantage of steam-alkali injection compared to pure steam injection for an 11.6° API Bati Raman crude oil. The steam injection system consists of two reservoirs for water and the alkali solution, an electrical pump, and an electric steam generator. Those three experiments are as follows; conventional pure steam injection, cyclic injection of steam and alkali solution 4.0 wt%, and cyclic injection of steam and alkali solution 8.0 wt%. Steam was injected with the rate of 10 ml/min at 110°C and the system pressure was set to be the atmospheric pressure. The liquid produced from the separators is sampled periodically to determine the oil recovery.
Observation of sand packs after the experiments indicates the tendency for steam channeling in the vertical direction around the upper thermocouple. Since the upper thermocouple was inserted after the sand packing operation by pressing and rotation, steam could be passed through these channels without entering the all pores in the porous media. The average oil recovery by conventional pure steam injection, steam-alkali solution 4.0 wt% injection, and steam-alkali solution 8.0 wt% are 8%, 3% and 5.5% OOIP (original oil in place), respectively. This indicates that although the oil recovery in conventional pure steam injection was maximum, increasing the alkali concentration in the aqueous solution from 4% to 8% has caused the improvement in the recovery.
The theoretical and practical information is supported by the experimental examples to evaluate the performance of different steam-alkali flooding strategies with Borax in heavy oil reservoirs of Bati Raman. This study also examines the challenges of steam-alkali flooding in extremely heavy oil reservoirs and explains that the pure steam injection is preferred due the insufficient change in interfacial tension during Borax injection process.
Enhanced oil recovery (EOR) from heavy oil reservoirs is challenging. The higher viscosity of oil in such reservoirs, add more challenges and severe the difficulties during any EOR method (i.e. high mobility ratio, inadequate sweep, reservoir heterogeneity) compared to that of EOR from light oil reservoirs. Foam has gained interest as one of the EOR methods especially for challenging and heterogeneous reservoirs containing light oil. However, the foam and especially polymer enhanced foam (PEF) potential for heavy oil recovery is less studied.
The current study aims to evaluate the performance of CO2 foam and CO2 PEF during heavy oil recovery from both unconsolidated (i.e. sandpack) and consolidate (rock sample) porous media with the help of fluid flow experiments. The injection pressure profile, oil recovery, and CO2 gas production were monitored and recorded to analyze and compare the performance of CO2 foam and PEF for heavy oil recovery. A visual sandpack made of glass column and a core-flood system capable of measuring the pressure at different sections of the core were used in this study. Homogenous and fractured sandstone core samples, as well as a fractured carbonate core sample, were selected for the core-flood study.
Static stability results revealed slower liquid drainage and collapse rates for PEF compared to that of foam even in the presence of heavy crude oil. The addition of polymer significantly improved the performance of CO2 foam flooding during heavy oil recovery in dynamic experiments. This result was inferred from faster propagation rate, higher dynamic stability, and higher oil recovery of CO2 PEF over CO2 foam injection. Moreover, the visual analysis demonstrated more stable frontal displacement and higher sweep efficiency of PEF compared to the conventional foam flooding. In the fractured porous media, additional heavy oil recovery was obtained by liquid diversion into the matrix area rather than gas diversion inferred from pressure profile and gas production data.
The results obtained from this study show that CO2 PEF could significantly improve the heavy oil recovery and CO2 sequestration, especially in homogeneous porous media.
Lu, Xiao (The University of New South Wales) | Armstrong, Ryan (The University of New South Wales) | Yuan, Meng (The University of New South Wales) | Zhang, Yulai (The University of New South Wales) | Mostaghimi, Peyman (The University of New South Wales)
Coalbed methane (CBM), also known as coal seam gas, is becoming an increasingly important energy resource in the global natural gas market. Gas transport in CBM reservoirs remains a crucial research topic that has not been fully understood. Two scales of gas flow are identified in coal cores: flow in fractures and diffusion within matrix. The diffusion process is quantified by the gas diffusion coefficient while flow in fractures is governed by fracture apertures. This paper aims to explore the diffusion process in coal using X-ray microcomputed tomography (micro-CT) imaging. The experiments are conducted at 100 psi effective stress to eliminate the impact of pressure. The images obtained are registered for visualisation and analysis of the diffusion process and comparisons of fracture. In the paper, the impact of increasing effective stress on fracture aperture is demonstrated. Also, the diffusion coefficient of Krypton in coal matrix is estimated and discussed.
Summary: Abrupt and large changes in the earth properties (velocities) can cause conversion of the compressional waves to converted mode energy. Such converted waves could be recorded on the towed streamer seismic data. If they are not identified and removed early they can mislead the interpretation. In this paper, we are showing the successful application of the converted wave attenuation (CWA) workflow on the seismic data from the Mediterranean See, Offshore Egypt. Data is acquired with latest broadband technique and went through several iterations of velocity model building. The presence of the strong converted waves has threatened to undermine velocity model building and interpretation effort. The benefit of presented workflow is that it identifies and models the converted energy pre-stack pre-migration, however the subtraction is done pre-stack post-migration. Post-imaging subtraction gives improved flexibility in signal protection and improvements in the S/N ratio, especially in the areas where the separation of the converted more and compressional energy is small. Presented workflow is universally applicable to any areas where the converted modes occur.
Tong, Zheng (Research Institute of Petroleum Exploration & Development, PetroChina) | Ma, Bing (ChangQing Oilfield Company, PetroChina) | Wei, Ran (Research Institute of Petroleum Exploration & Development, PetroChina) | Liao, Chenglong (Research Institute of Petroleum Exploration & Development, PetroChina) | Liu, Shun (ChangQing Oilfield Company, PetroChina) | Huang, Peng (Research Institute of Petroleum Exploration & Development, PetroChina) | Wang, Xinzhong (Research Institute of Petroleum Exploration & Development, PetroChina)
Operator planned to develop the new low-permeable sandstone gas reservoir below the mature gas layer in Ordos basin. In terms of cost reduction the wellbore was designed to pass through the undeveloped resource locating in the upper mature reservoir to obtain dual-zone commingled production. According to the well logging, there was the indication of hole collapse, enlargement and an unforseen water bearing zone found in the deviated section locating in upper zone. Packers could fail in the irregular deviated wellbore.
Upon the modification of completion solution, the 4 1/2in open-hole packer-sleeve (OHPS) completion and fracturing system was deployed to treat the lower target zone. Top cementing operation using novel stage collar with swellable elements was performed to isolate the upper mature zone. "Plug and Perf" (PnP) via compact bridge plugs was carried out to enable efficient fracturing in deviated wellbore. The single-trip OHPS system employed water-swellable packers (WSPs) with corrugated packing element.
The WSP and compact bridge plug were successfully evaluated by bench test. In one gas well, the operator performed cementing job and the stage collar was opened by wiper plug once the tripping of the OHPS completion with five packers was made successfully. Three bridge plugs were pumped down to the target depth. Hydraulic fracturing operation was sequentially made with all packers and bridge plugs effectively set. It is shown from the field operation that the hybrid completion is able to meet the requirements of completion and stimulation in irregular wellbore with abnormal conditions for tight reservoirs.
The coinjection of carbon dioxide (CO2) or light hydrocarbons with steam in the steam-assisted-gravity-drainage (SAGD) process might enhance bitumen mobility and reduce the steam/oil ratio (SOR). Understanding and modeling the phase behavior of solvent/bitumen systems are essential for the development of in-situ processes for bitumen recovery. In this paper, an experimental and modeling study is undertaken to characterize the phase behavior of bitumen/CO2 and bitumen/C4 systems. Produced and dewatered oil from the Cenovus Osprey Pilot is used for the experiments. The Osprey Pilot produces oil from the Clearwater Formation. Constant-composition-expansion (CCE) experiments are conducted for characterizing Clearwater bitumen, CO2/bitumen mixture, and C4/bitumen mixture. The Peng and Robinson (1978) equation of state (EOS) (PR-EOS) is calibrated using the measured data and is used for pressure/volume/temperature (PVT) modeling. Multiphase equilibrium calculations are performed to predict the solubility of CO2 and C4 in the temperature range of 393.2 to 453.2 K. The potential of asphaltene precipitation for CO2/bitumen and C4/bitumen mixtures is also investigated using three screening criteria.
According to the CCE tests and multiphase equilibrium calculations, C4 has much higher solubility in bitumen than does CO2 at operating pressure of 3997.9 kPa and temperature between 393.2 and 453.2 K (393.2 K < T < 453.2 K). During the CCE tests, coexistence of three equilibrium phases is observed for the C4/bitumen system with high C4 concentration. The three phases consist of a heavy oleic phase (L1), gaseous phase (V), and a light (solvent-rich) oleic phase (L2). Compositional analysis of the samples from L1 and L2 phases shows that C4 can extract light hydrocarbon components from bitumen into the L2 phase and preserve the heavy components in the L1 phase. Also, the L2 phase becomes darker by increasing the pressure, suggesting the extraction of heavier hydrocarbon components at higher pressures. Similar tests on the CO2/bitumen system show only two effective phases over a similar temperature range. The two phases consist of a heavy oleic phase (L1) and a gaseous phase (V).
Phase-equilibrium regions are predicted using the regressed EOS model in the compositional space for the solvent/bitumen system. EOS predictions indicate two types of two-phase regions in the composition space for the C4/bitumen system (i.e., L1/L2 when 393.2 K < T < 421.2 K and L1/V when 421.2 K < T < 453.2 K). However, only one type of two-phase region (i.e., L1/V) exists in a similar temperature range for a CO2/bitumen system. The EOS predictions show that 1.8 wt% CO2 can reduce bitumen viscosity by up to 1.4 times, and 16.3 wt% C4 can reduce bitumen viscosity by up to 20 times when 393.2 K < T < 453.2 K. Viscosity calculations indicate that oil dilution by CO2 and C4 dissolution is more effective at lower temperatures, especially for C4. This shows the potential of injecting hot hydrocarbon solvents for bitumen recovery. The results show that asphaltene might precipitate in a system of C4/bitumen with high C4 concentration.