Complex Toe-to-Heel Flooding (CTTHF) is a short distance flooding technique developed by the authors for sandstone formations. CTTHF applied on horizontal wells and requires at least one barrier and injector hydraulic fracture, also it requires at least one method to control early water production. This paper discusses the design aspects of the CTTHF including the design of barrier fracture, injector fracture, and the produced water control methods. Technical and economical evaluation to rank different design setups is performed and presented.
Advanced commercial reservoir simulator with hydraulic fracturing module was used to simulate different CTTHF setups and reservoir conditions to set the reservoir selection criteria and proper design methodology. In this study, Toe-to-Heel Waterflooding was considered the base case. Sensitivity studies for barrier fracture and injector design has been achieved and presented. Moreover, a sensitivity studies for hydraulic fractures spacing, number of barrier fractures, batch injection scheduling and changing packer location have been performed.
When CTTHF is applied in high permeable sandstone formation, early water production is expected, except produced water control method is used. This study states the feasibility conditions for each proposed produced water control technique. Also, a methodology for candidate reservoir selection, design of barrier and injector fractures is developed and presented. There are multiple fluid systems can be used to create the barrier to seal a pre-determined zone. CTTHF is better reservoir management approach.
The novelty of the CTTHF is giving multiple options for produced water control that maximizes the produced oil and minimizes the water production. CTTHF's produced water control can make some reservoirs economic to produce.
Indonesia’s oil reserves continue to decrease each year. The amount of oil produced is greater than the amount of new reserves discovered. To overcome this imbalance, various efforts have been made by the government in increasing oil lifting. In addition to exploration activities, other efforts that can be done to improve oil lifting are through Improved Oil Recovery (IOR).
Since the establishment of SKK Migas, a total of 431 oil and gas Field Development Plans (FDP) have already been approved by the Government of Indonesia (as of December 2017) and about 31 of them were already using IOR methods (water flood and steam flood). Along with the sharp decline rate in Indonesia, more IOR projects are needed to restrain the decline oil rate in Indonesia. To attract and help contractors so they are willing to do the IOR projects, the Government of Indonesia offer an incentives such as investment credit and/or interest of cost recovery so that the IOR projects can be developed more economically. Moreover, there are some tools which these contractors may use to improve the economical nature of their projects, such as DMO Holiday, Depreciation Acceleration, Shared First Tranche Petroleum, Split Changes, and many more.
The purpose of this paper, is to obtain the average Production Costs of IOR Projects in Indonesia, which divided into 3 different IOR areas (North Sumatera, South Sumatera, and Kalimantan) based on the 31 IOR FDP projects. The data of the 31 IOR Projects were collected and afterwards the Profitability Index and Development Cost were calculated and distributed to those aforementioned areas.
The result of this paper showed that the lowest average production cost was in North Sumatera by 10 US$ per barrels and the highest average production cost of IOR projects in Indonesia was in Kalimantan by 25 US$ per barrels which remain lower than the current oil price. Based on the obtained production cost above, it can be concluded that the Indonesian IOR Projects are economically acceptable and hopefully can attract more contractors to propose IOR Projects in Indonesia.
The compositional flow simulation model was frequently used to evaluate the miscible water alternating CO2 flooding (CO2-WAG). The uncertainty and sensitivity analysis have to be conducted to examine the parameters mostly affecting the performance of the process. Accordingly, multiple simulation runs require to be constructed which is a time-consuming procedure and finally increase the computational cost. This paper presents a simplistic approach to assess the miscible CO2-WAG flooding in an Iraqi oilfield through developing a statistical proxy model. The Central Composite Design (CCD) was employed to build the proxy model to determine the incremental oil recovery (ΔFOE) as a function of seven reservoir and operating parameters (permeability, porosity, ratio of vertical to horizontal permeability, cyclic length, bottom hole pressure, ratio of CO2 slug size to water slug size, and CO2 slug size). In total, 81 compositional simulation runs were conducted at field-scale to establish the proxy model. The validity of the model was investigated based on statistical tools; the Root Mean Squared Error (RMSE), R-squared statistic and the adjusted R-squared statistic of 0.0095, 0.9723 and 0.9507 confirmed the reliability of the model. The most influential and the optimum values of the parameters that lead to the higher ΔFOE during miscible CO2-WAG process were identified through proxy modeling analysis. The developed model was created based on the Nahr Umr reservoir in Subba oilfield and can be applied to roughly estimate the ΔFOE during the miscible CO2-WAG process at the same geological conditions as Nahr Umr reservoir.
With maturing oil fields there is an increasing focus on improving the oil recovery factor and pushing the envelope toward a 70% target. This target is indeed very challenging and depends on a number of factors including enhanced oil recovery (EOR) methods, reservoir heterogeneities, displacement efficiency, and reservoir sweep. Other factors also play a role including vertical sweep due to flow behind the casing, well integrity issues, presence of conductive faults, or fractures. Proper surveillance performed to evaluate the injectant plume front, reservoir conformance, well connectivity, assessment of the integrity of wells, and other factors can be crucial for the success of the project and its future development.
The paper discusses special downhole logging techniques including a set of conventional multiphase sensors alongside high precision temperature (HPT) and high-definition spectral noise logging (SNL-HD). It was run to provide complete assessment of the injection – production distribution and any associated well integrity issues that might impair the lateral sweep of injectants into the target layer. This will be done for an injector and producer pair near the wellbore area. The operation was carried out with a tool string that contained no mechanical parts and was not affected by downhole fluid properties. It was conducted under flowing and shut-in conditions to identify flow zones and check fracture signatures. It also provided multiphase fluid velocity profiles.
The results of the survey allowed for in-depth assessment of borehole and behind casing flow, confirming lateral continuity, and provided an assessment of production-injection outside the pay zone. Results will allow for better well planning and anticipation of possible loss of well integrity that might impair production in the future. Combining the behind casing flow assessment with borehole multiphase flow distribution can be used for production optimization by sealing unwanted water contributing zones.
Liang, Jiabo (CNOOC Iraq Limited) | Jin, Liping (CNOOC Iraq Limited) | Li, Wenyong (CNOOC Iraq Limited) | Li, Qiang (CNOOC Iraq Limited) | Laaby, Hussein Kadhim (Missan Oil Company) | Ammar, Ali Jabbar (Missan Oil Company) | Tayih, Ali Ouda (Missan Oil Company) | Muteer, Raad Fahad (Missan Oil Company) | Saadawi, Hisham N H (Baker Hughes, a GE company) | Harper, Christopher (Baker Hughes, a GE company) | Tuck, Jon O. (Baker Hughes, a GE company) | Fang, Yongjun (Baker Hughes, a GE company)
CNOOC Iraq Limited operates three oil fields in Missan Province in Iraq. They are all large onshore oilfields located 350 kilometers southeast of Baghdad. In order to support reservoir pressure, plans are underway to implement a water injection scheme. The injection water comes from three different sources; produced water, aquifer water as well as river / agricultural water. Considering the nature and varying chemistry of the source water, particular attention had to be given to selecting the material for the water injection wells. This paper describes the approach adopted in selecting the materials for Missan fields' water injection system.
AL-Rashidi, Hamad (Kuwait Oil Company) | AL-Azmi, Waled (Kuwait Oil Company) | AL-Azmi, Talal (Kuwait Oil Company) | Ahmed, Ashfaq (Kuwait Oil Company) | Muhsain, Batoul (Kuwait Oil Company) | Mousa, Saad (Kuwait Oil Company) | AL-Kandari, Noor (Kuwait Oil Company) | AL-Sabah, Fahad (AL-Thurya) | AL-Hajri, Mohsen (BG) | AL-Mutwa, Bandar (AAA)
Crude oil production in Um-Ghdair field is consider one of the most complex operational activities in Kuwait Oil Company due to high water cut percentage, asphaletene flocculation, high viscosity and tight emulsion phenomena. As the fluid travels through the reservoir, wellbore, flowline, all the way to the gathering center, the state of initial equilibrium is disturbed leading to change in the chemical composition of the crude oil. As pressure and temperature continue to drop, and gas escapes, more asphaltenes and heavy components may continue to flocculate all the way throughout the system until the petroleum reaches its final destination. In this pilot project, asphaltene inhibitor and viscosity reducer agents were selected for reducing oil viscosity and breaking the tight emulsion phenomena in the selected piloting well in Um-Ghdair field. It was noticed that there is an asphaltene compounds flocculate in the interface between oil and water leading to increase crude oil viscosity. The best two among 22 chemical formulations tested through the screening process at lab scale and take it to pilot stage. Additionally, the pilot study examined the influences effective for surfactants such as water composition, temperature, concentration, pH and total dissolved solids. It was noticed that the viscosity reduction and the water separation improve with increasing surfactant concentration and increasing temperature up to 50 F. Two formulations were selected based on cost effective optimal concentrations of surfactant that identified from the bottle test. The pilot has been implemented successfully in the field, resulting a reduction in non-production time and increase the oil mobility from the reservoir.
We interpreted a series of single-well-chemical-tracer-tests (SWCTTs) estimating residual oil (SORW) to base high salinity waterflood, low salinity waterflood and subsequent polymer flood conducted on a Greater Burgan well. Interpretation of the tests requires history matching of the back-production of partitioning and non-partitioning tracers which is impacted by differing amounts of irreversible flow and differing amounts of dispersion as well as the amount of residual oil.
We applied the state-of-the-art chemical reservoir simulator (UTCHEM) and an assisted history matching tool (BP’s Top-Down-Reservoir-Modeling) to interpret the tests and accurately quantify uncertainty in residual oil saturations post high salinity, low salinity, and polymer floods. Two optimization algorithms (i.e., Genetic algorithm (GA) and Particle-Swarm-Optimization (PSO)-Mesh-Adaptive-Direct-Search (MADS) algorithms) were applied to better address the uncertainty.
Our results show a six saturation unit decrease in SORW post low salinity with no change to the SORW post polymer. This is in-line with our expectations - we expect no change in SORW post-polymer as the conventional HPAM, which does not exhibit visco-elastic behavior, was used in the test. We demonstrate that history matching the back-produced tracer profiles is a robust approach to estimate the SORW by showing that three-or four-layer simulation model assumption does not change the SORW estimated. We accounted for the uncertainty in partition-coefficient in our uncertainty estimates.
We present several innovations that improve history matching back-produced tracer profiles; hence, better SORW estimations (e.g., different level of dispersivity for individual simulation layers to account for different heterogeneity level as opposed to assuming a single dispersion for all layers). We generate more robust estimates of uncertainty by finding a range of alternative history matches all of which are consistent with the measured data.
Alhuraishawy, Ali K. (Iraqi Ministry of Oil / Reservoir and Fields Development Directorate) | Jaber, Ahmed Khalil (Iraqi Ministry of Oil / Reservoir and Fields Development Directorate) | Aljawad, Sameer Noori (Iraqi Ministry of Oil / Reservoir and Fields Development Directorate) | Bai, Baojun (Missouri University of Science and Technology) | Wei, Mingzhen (Missouri University of Science and Technology) | Baker, Hussein Ali (Baghdad University) | AL-Bazzaz, Waleed Hussien (Kuwait Institute for Scientific Research)
The limitations of oil recovery from carbonate reservoirs are fractures and oil-wet conditions. To overcome the reservoir heterogeneities and reduce fracture transmissibility, preformed particle gel was applied in injector wells. Experimentally, low salinity waterflooding was applied to change the core wettability from oil-wet to water wet for enhanced oil recovery. However, both processes have limitations that cannot be resolved using a single method. A nonuniform fracture width and uniform fracture width models were built using carbonate cores to evaluate the coupling low salinity waterflooding and preformed particle gel in fractured cores and how could be used to improve in-depth water diversion treatment. The results showed that low salinity waterflooding improved in-depth water diversion when injected after PPG directly while seawater showed less effect than low salinity waterflooding. Also, the uniformity of fracture had a significant effect on plugging efficiency oil recovery factor from fractured reservoirs.
Jason Crew was appointed as CEO and a member of the board of directors at Summit Power. Crew comes to Summit from General Electric, where he was most recently responsible for the GE distributed power specialty fuels business segment, focusing on launching technologies for distributed biomass gasification-to-power, integrated systems, and the production of CO2 for enhanced oil recovery. From 2011 to 2013, Crew led GE's global gasification and integrated gasification combined cycle business from Shanghai. He will succeed current CEO Eric Redman, who will assume the role of co-chair of the board of directors while continuing to focus on the Texas Clean Energy Project. Crew holds a bachelor's degree in electrical engineering from Auburn University and an MBA from the Fuqua School of Business at Duke University.
Rognmo, Arthur U. (University of Bergen) | Al-Khayyat, Noor (University of Bergen) | Heldal, Sandra (University of Bergen) | Vikingstad, Ida (University of Bergen) | Eide, Øyvind (University of Bergen) | Fredriksen, Sunniva B. (University of Bergen) | Alcorn, Zachary P. (University of Bergen) | Graue, Arne (University of Bergen) | Bryant, Steven L. (University of Calgary) | Kovscek, Anthony R. (Stanford University) | Fernø, Martin A. (University of Bergen)
The use of nanoparticles for CO2-foam mobility is an upcoming technology for carbon capture, utilization, and storage (CCUS) in mature fields. Silane-modified hydrophilic silica nanoparticles enhance the thermodynamic stability of CO2 foam at elevated temperatures and salinities and in the presence of oil. The aqueous nanofluid mixes with CO2 in the porous media to generate CO2 foam for enhanced oil recovery (EOR) by improving sweep efficiency, resulting in reduced carbon footprint from oil production by the geological storage of anthropogenic CO2. Our objective was to investigate the stability of commercially available silica nanoparticles for a range of temperatures and brine salinities to determine if nanoparticles can be used in CO2-foam injections for EOR and underground CO2 storage in high-temperature reservoirs with high brine salinities. The experimental results demonstrated that surface-modified nanoparticles are stable and able to generate CO2 foam at elevated temperatures (60 to 120°C) and extreme brine salinities (20 wt% NaCl). We find that (1) nanofluids remain stable at extreme salinities (up to 25 wt% total dissolved solids) with the presence of both monovalent (NaCl) and divalent (CaCl2) ions; (2) both pressure gradient and incremental oil recovery during tertiary CO2-foam injections were 2 to 4 times higher with nanoparticles compared with no-foaming agent; and (3) CO2 stored during CCUS with nanoparticle-stabilized CO2 foam increased by more than 300% compared with coinjections without nanoparticles.