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Results
Abstract A prototype apparatus integrating a state-of-the-art micro-slim tube (MST) was developed and tested for rapid determination of Minimum Miscibility Pressure (MMP). The equipment, GEMA (Gas Extraction & Miscibility Analyser), uses an advanced technology of data acquisition and control system, making it a reliable tool for rapid MMP determination. MST is an unpacked, coiled stainless steel column of 30 m long and 0.32 mm ID. The small bore capillary column permits a high linear displacement rate resulting in a much shorter time needed per test of only 2 to 3 hours (including cleaning) as compared to 2–3 days if the conventional slim tube apparatus is used. The relatively small height-equivalentto-a-theoretical-plate (HETP) in a capillary column ensures thousands of multiple contacts between the injected gas and oil, which cannot be practically achieved in the conventional slim tube. With this newly upgraded equipment, MMP determination for one sample takes only 2–3 days to complete as opposed to 2–3 weeks with the normal slim tube. The method has been tested for various Malaysian reservoir fluid samples and the MMP results obtained are consistent with values estimated using published correlations such as Johnson & Pollin (1981), Glaso (1985) and Cronquist (1978). The equipment is proven to be very reliable to determine the MMP. Introduction The minimum miscibility pressure (MMP) is the pressure at which the injected gas and the contacted oil in place become miscible with each other resulting in a very efficient displacement process. When miscibility occur, the capillary forces which trap the oil in the formation, diminishes and the oil is then more mobile, leading to an enhanced oil production. Reliable determination of MMP is therefore required. MMP could be determined experimentally using slim-tube, sand-pack or rising bubbles experiments. It can also be estimated numerically using compositional simulation (equation-of-state), mixing cell models, and correlations. Using correlations could be the easiest available method to estimate MMP. However, the application might be limited in such a way that the properties of the fluid of interest need to fall within the range of properties used to develop the correlation in the first place. The slim tube test, which is one of the most widely used techniques to measure MMP, inherits many problems including difficulties associated with the relatively large column diameter used and the difficulties in obtaining uniform packing thus difficult to get repeatable results between different runs or different laboratories. In addition, it needs several days to run optimal tests with a slim-tube packed column. GEMA, on the other hand, uses a state-of-the-art unpacked micro-slim tube that enables rapid determination of MMP. The relatively small height-equivalent-to-a-theoreticalplate (HETP) in the capillary column ensures thousands of multiple contacts between the injected gas and the oil, which cannot be practically achieved in the conventional slim tube. The small bore capillary column permits a high linear displacement rate resulting in the time needed per test to be much shorter as compared to the conventional slim tube. GEMA was calibrated against displacement tests on Hexadecane-CO2 and Decane-CO2 at 50°C and 39°C, respectively, as conducted by Johnson & Pollin. The equipment has also been used to determine the CO2 MMP for various Malaysian oil samples. The results show that the MMPs determined by GEMA are in good agreement with those estimated by established correlations. Background GEMA was jointly invented by a successful collaboration between PETRONAS Research & Scientific Services and BRTR Petroleum Consultant, Canada in 1995. A technical paper on GEMA application was first published in 1999 by Kechut et al.. This prototype equipment was recently upgraded to include a high precision data acquisition system, an automatic heating system and customized in-house program for a more accurate breakthrough time with a sampling rate of 0.5 seconds and real-time UV response difference could be recorded which lead to more accurate MMP determination.
- Asia (0.89)
- North America > United States (0.68)
Geo-engineering and Economic Assessment of a Potential Carbon Capture and Storage Site in Southeast Queensland, Australia
Cinar, Yildiray (U. of New South Wales) | Sayers, Jacques (Australian School of Petroleum) | Neal, Peter Ross (University of New South Wales) | Allinson, William Guy (U. of New South Wales)
Abstract This paper presents geo-engineering and economic sensitivity analyses and assessments of the Wunger Ridge flank Carbon Capture and Storage (CCS) site. A numerical reservoir simulation examines injection rates ranging from 0.5 to 1.5 million tonnes of CO2/year. Primary factors affecting the ability to inject CO2 include permeability, formation fracture gradient, and multiphase flow functions. Secondary factors include the solubility of CO2 in the formation brine, injection well location with respect to the flow barriers/low-permeability aquifers, model geometry including faults, grid size and refinement, and injection well type. Less significant factors include hydrodynamic effects. The economics are assessed using an internally developed techno-economic model. The model optimises the CO2 injection cost based on geo-engineering data and recent equipment costs. The overall costs depend on the initial costs of CO2 capture and on source-to-sink distances and their associated pipeline costs. Secondary cost variations are highly dependant on fracture gradient, permeability and CO2 injection rates. Depending on the injection characteristics, the specific cost of CO2 avoided is between A$30 and A$44 per tonne. Introduction Australia's fossil fuel-fired power plants emit about 194 million tonnes of CO2 each year (Mt CO2/yr), and about 26 Mt/yr of this come from southeast Queensland. A multidisciplinary study has recently identified the onshore Bowen Basin as having potential for geological storage of CO2. In that paper, geological containment and injectivity, as well as reservoir engineering simulation sensitivities showed that a target injection rate of 1.2 Mt CO2/yr over a 25 year project life-span could be achieved (i.e. equivalent to injecting the emissions from a 400 MW gas-based power station). This study further examines reservoir engineering and economics sensitivities. Background Sayers et al. have recently showed that acceptable CO2 injection rates were dependent on critical parameters including:reservoir permeability, maximum allowable injection pressure, dissolution effects of the CO2, injection well location relative to the aquifer boundary, aquifer and model geometry, structural gradient changes at reservoir level, wellbore modelling, and treatment of the aquifer in simulation (i.e. numerical versus analytical). The above technical parameters, listed in order of importance, represent CCS site technical considerations as opposed to project risk or economic considerations. Cook noted that the Australian CCS scene presently required demonstration sites to test concepts in a whole-of-project sense. Following the construction of a demonstration site in south-east Australia, it is hoped that further sites such as Wunger Ridge will proceed. Figure 1 shows the location of the Bowen Basin and study area of the potential CCS site. A 10×30 km area, on the downdip eastern flank of a 60-km NNE trending ridge was chosen. Petroleum has been produced from the updip parts of the Basin for the last 30 to 40 years. The Showgrounds Sandstone potential CO2 containment reservoir is sealed by the Snake Creek Mudstone and Moolyember Mudstone formations (Figure 2). Geological and geophysical complexities have been addressed in Sayers et al.. Southeast Queensland has a buoyant energy sector. The above region and Bowen Basin in general has seen development of coal mines and coal seam methane projects. The Cooper-Roma-Brisbane natural gas pipeline also passes through the region. Finally, there are many existing and proposed power plants with almost to 6,000 MW of black coal generating capacity and almost 1,000 MW of natural gas generating capacity.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.68)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (0.54)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.49)
- Oceania > Australia > Victoria > Otway Basin (0.99)
- Oceania > Australia > South Australia > Otway Basin (0.99)
- Oceania > Australia > South Australia > Eromanga Basin (0.99)
- (12 more...)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
Abstract The BDO EOR feasibility study conducted in 2004 by PETRONAS and Sarawak Shell Berhad (SSB) identified a potential incremental recovery of over 250 MMstb from the Baram Delta Operation (BDO) fields. This incremental oil can be realized from CO2 injection under miscible and immiscible conditions. On average, this represents an additional 12% incremental recovery above the base case of water flooding. The regional CO2 injection covering nine (9) fields requires a very significant investment of new CO2 infrastructures and injection facilities. To mitigate the risk involved and to prove the commercial viability of the project, a regional pilot was proposed. The pilot, which will be implemented in Baronia RV2 reservoirs, will serve as a basis to formulate the way forward for CO2 injection in the whole BDO region. Several extensive evaluations were carried out to come up with an optimized pilot design. This includes building full field compositional fluid flow simulation model for CO2 miscible flood predictions and sensitivities, streamlines analysis to identify suitable well pairing, and MMP / interfacial tension measurements in the laboratory. The proposed observation pilot were specifically designed to address several issues such as determination of current oil saturation, waterflood residual oil saturation, residual oil saturation after gas flooding and evaluation of the vertical sweep efficiency. The pilot will also serve as an opportunity to acquire additional data through extensive coring, logging, and fluid sampling programs. This paper outlines the methodology used in the developing the most cost-effective pilot at Baronia RV2 reservoirs that could potentially lead to economic maturation of new reserves in the whole of the BDO area as well as formulating the most comprehensive monitoring and evaluation techniques of the pilot. Introduction The Baram Delta area which is located at offshore Miri of Sarawak consists of nine (9) fields as shown in Figure 1. The area which was discovered in 1969 is estimated to have more than 4000+ MMstb oil in place with multiple stacked sandstone reservoirs in a shallow offshore environment. They have been on production for more than 30 years and the historical production data indicated that the oil production have been relatively flat at 80 - 100 kbd of oil primarily from infill drilling and new in-field development and/or rejuvenation. Figure 2 shows historical production performance of the BDO area. Currently, many wells are shut in due to the high water production. Because of offshore environment, well spacing is relatively large and limited available space at the platform which make these characteristics present a challenging environment to carry out EOR operations. The stratagraphic framework for Baram Delta reservoirs is mainly from Middle Miocene in age with east-west oriented coastline and a delta progradation southeast to northwest as shown in Figures 3 and 4. The principal reservoirs are cycle V/VI regressive coastal plan and fluvio-marine sandstones. The depositional environments observed vary where shoreface deposits exhibit higher connectivity and higher areal sweep. The multiple stacked pays in multiple fields means that there are most probably many thief zones in the area reflected by a low recovery factor of around 29% only. Looking at this issue positively, it can be inferred that BDO area still has a lot of future oil potential through EOR applications.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.74)
- Geology > Sedimentary Geology (0.54)
- Asia > Malaysia > Sarawak > South China Sea > Sarawak Basin > Baram Delta Province > Block SK307 > West Lutong Field (0.99)
- Asia > Malaysia > Sarawak > South China Sea > Sarawak Basin > Baram Delta Province > Bokor Field (0.93)
- Asia > Malaysia > Sarawak > South China Sea > Sarawak Basin > Baram Delta Province > Block SK307 > Betty Field (0.93)
- Asia > Malaysia > Sarawak > South China Sea > Sarawak Basin > Baram Delta Province > Block SK307 > Baronia Field (0.93)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract In the past, the elasticity of the displacing solution was not considered when the influence of capillary number on displacement efficiency was studied. Recent years, the theory that the visco-elasticity of flooding fluid can increase displacement efficiency has been gradually accepted, but the present research level cannot quantitatively describe the effect of elasticity on elasticity. In this paper, the first normal-stress difference was used to characterize the elasticity of polymer solutions, the influence of capillary number on displacement efficiency and residual oil saturation after flooding by different visco-elastic polymer solutions is studied through experiments on weak oil-wet artificial homogeneous cores. Also, at the same capillary number, the influence of the visco-elastic property of polymer solutions on displacement efficiency and residual oil saturation is studied. A set of curves of capillary number versus displacement efficiency after flooding by different visco-elastic polymer solutions is obtained. The results show that the capillary number and visco-elasticity both influence the displacement efficiency and residual oil saturation. Under conditions of same capillary number, the higher the visco-elasticity of the polymer solution, the higher the displacement efficiency, the lower the residual oil saturation, the visco-elasticity of polymer solution can significantly increase recover efficiency and lower residual oil saturation. Introduction In the past, many researchers did not considered the influence of visco-elastic behavior of polymer (HPAM) solutions on the flooding efficiency. Some even considered that the viscoelastic effect of the polymer (HPAM) solutions can be ignored in normal polymer flooding,. In recent years, more and more research results show that the viscoelasticity of polymer solutions can increase the microscopic oil displacement efficiency, therefore, the viscoelasticity of polymer solutions should not be neglected . But there are still few reports about the effect of the viscoelasticity of polymer solution on the relationship of the capillary number and the displacement efficiency. Prof. Lv Ping conducted experiments only in natural cores from Daqing Oil Field, and found the relations between the capillary number and the residual oil saturation under the condition of no viscoelasticity. In this paper, through experiments in artificial cores, the influence of the capillary number on the displacement efficiency of different viscoelastic polymer solutions is discussed. The results are helpful for the further study of the mechanism of polymer flooding, and they can be of reference to polymer flooding field trials. Materials and experimental procedures Materials Surfactant: alkyl benzene sulfonate ORS41, non-ionic NOS; Polymer: partially hydrolyzed polyacrylamide (HPAM), molecular weight 18×10 Daltons; Alkali: NaOH; Water: the salinity of water used to saturate the cores is 6778 mg/L; the salinity of the water to prepare polymer/surfactant systems is 508 mg/L, and 3700mg/L for alkali/surfactant systems. Oil: a simulation oil of kerosene and crude oil that comes from No.4 Company of Daqing oil field, the viscosity of the simulated oil is 9.8 mPa.s at the tested temperature (45?). Artificial cores: homogeneous cores made by silica sand and epoxy (size: f2.5×10cm), the oil wettability indicator is 0.64, the water wettability indicator is 0.4; Equipments Interfacial tensionmeter: TX500 interfacial tensionmeter made by Texas University. Rheometer: LS-30 rheometer made in Switzerland and HAKKE RS-150 rheometer made in Germany. Flooding equipments: thermostat, core holder, electric high pressure pump, manual high pressure pump, vacuum pump, pressure sensor etc.
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
Abstract The polymer flooding has been developed and applied for more than ten years in Daqing Oilfield of China, and the oil recovery in major reservoirs (referring to the reservoirs with high permeablity and thickness) has improved more than 10% of OOIP, which has played an indispensable role in controlling oil decline for the oilfield. But with the enlargement of application of polymer flooding, its potential in major reservoirs decreased, the poor reservoirs (referring to the reservoirs with low permeablility and thickness more than 1m but less than 4m) will be the main substitutable targets in the future. The laboratory studies and field practice show that, compared with the major reservoirs, the poor reservoirs are thin and multi-layered with the characteristics of low permeability, complicated connectivity, frequent facies changes in horizontal direction and high diversity between layers in vertical direction. Therefore the technologies used in major reservoirs are not suitable for poor reservoirs. It is necessary to develop the technologies that adapt to geological characteristics of poor reservoirs. Considering the geological specifics of medium reservoirs and the field results from the pilot test, the concept of accessible ratio of polymer flooding is defined and the project designed for polymer flooding in poor reservoirs has been optimized. The five-year laboratory studies and field tests indicate that polymer flooding is feasible for poor reservoirs. Combined with infilling well pattern, the oil recovery of polymer flooding for poor reservoirs is more than 10% higher than water flooding. The integrated technologies related to polymer flooding for poor reservoirs have been widely applied in the northern parts of Daqing Oilfield. Introduction During the industrialization of polymer flooding in major reservoir, a series of technologies suitable for geological specifics of major reservoir in Daqing Oilfield have been developed. With the decrease of development potential of major reservoir, the poor reservoirs have been considered to put into production. In 2000, the pilot test of polymer flooding for poor reservoirs was conducted by use of the technologies applied for major reservoirs. But the results were not good due to its poor injectivity and productivity, indicating that the technologies for major reservoirs are not applicable for poor reservoirs. On the basis of the studies on geological characteristics of poor reservoirs, the project design method and the related technologies were achieved through laboratory studies, numerical simulation and field practice. In 2002, polymer flooding in poor reservoirs was performed in northern part of SaZhong area, making the technologies for poor reservoirs more complete, which can provide the foundation to develop poor reservoirs by polymer flooding.
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)