Field Realization of Adaptive Reservoir Simulation for Steam Injection Forecasting

2021 ◽  
Author(s):  
Stanislav Ursegov ◽  
Evgenii Taraskin ◽  
Armen Zakharian
Keyword(s):  
Oil Recovery ◽  
Oil Production ◽  
Steam Injection ◽  
Carbonate Reservoirs ◽  
Base Case ◽  
Simple Liquid ◽  
Limited Information ◽  
Viscous Oil ◽  
Production Wells ◽  
Liquid Displacement

Abstract Globally, steam injection for heavy and high-viscous oil recovery is increasing, including carbonate reservoirs. Lack of full understanding such reservoir heating and limited information about production and injection rates of individual wells require to forecast steam injection not only deterministic and simple liquid displacement characteristic modeling types, but also the data-driven one, which covers the adaptive modeling. The implementation and validation of the adaptive system is presented in this paper by one of the world's largest carbonate reservoirs with heavy and high-viscous oil of the Usinsk field. Steam injection forecasting in such reservoirs is complicated by the unstable well interactions and relatively low additional oil production. In the adaptive geological model, vertical dimensions of cells are similar to gross thicknesses of stratigraphic layers. Geological parameters of cells with drilled wells do not necessarily match actual parameters of those wells since the cells include information of neighboring wells. During the adaptive hydrodynamic modeling, a reservoir pressure is reproduced by cumulative production and injection allocation among the 3D grid cells. Steam injection forecasting is firstly based on the liquid displacement characteristics, which are later modified considering well interactions. To estimate actual oil production of steamflooding using the reservoir adaptive geological and hydrodynamic models, dimensionless interaction coefficients of injection and production wells were first calculated. Then, fuzzy logic functions were created to evaluate the base oil production of reacting wells. For most of those wells, actual oil production was 25 – 30 % higher than the base case. Oil production of steamflooding for the next three-year period was carried out by modeling two options of the reservoir further development - with and without steam injection. Generally, forecasted oil production of the option with steam injection was about 5 % higher. The forecasting effectiveness of cyclic steam stimulations of production wells was done using the cross-section method, when the test sample was divided into two groups - the best and the worst, for which the average forecasted oil rates after the stimulations were respectively higher or lower than the average actual oil rate after the stimulations for the entire sample. The difference between the average actual oil rates after the stimulations of the best and the worst groups was 32 %, i.e. this is in how much the actual oil production could have increased if only the best group of the sample had been treated.

Undersaturated Hydrocarbon Reservoir Waterflooding: A simulation Approach to Performance Assessment

2021 ◽  
Author(s):  
Adekunle Tirimisiyu Adeniyi ◽  
Miracle Imwonsa Osatemple ◽  
Abdulwahab Giwa
Keyword(s):  
Oil Recovery ◽  
Net Present Value ◽  
Oil Production ◽  
Base Case ◽  
Present Value ◽  
Sweep Efficiency ◽  
Recovery Method ◽  
Solution Approach ◽  
Hydrocarbon Reservoir

Abstract There are a good numbers of brown hydrocarbon reservoirs, with a substantial amount of bypassed oil. These reservoirs are said to be brown, because a huge chunk of its recoverable oil have been produced. Since a significant number of prominent oil fields are matured and the number of new discoveries is declining, it is imperative to assess performances of waterflooding in such reservoirs; taking an undersaturated reservoir as a case study. It should be recalled that Waterflooding is widely accepted and used as a means of secondary oil recovery method, sometimes after depletion of primary energy sources. The effects of permeability distribution on flood performances is of concerns in this study. The presence of high permeability streaks could lead to an early water breakthrough at the producers, thus reducing the sweep efficiency in the field. A solution approach adopted in this study was reserve water injection. A reverse approach because, a producing well is converted to water injector while water injector well is converted to oil producing well. This optimization method was applied to a waterflood process carried out on a reservoir field developed by a two - spot recovery design in the Niger Delta area of Nigeria that is being used as a case study. Simulation runs were carried out with a commercial reservoir oil simulator. The result showed an increase in oil production with a significant reduction in water-cut. The Net Present Value, NPV, of the project was re-evaluated with present oil production. The results of the waterflood optimization revealed that an increase in the net present value of up to 20% and an increase in cumulative production of up to 27% from the base case was achieved. The cost of produced water treatment for re-injection and rated higher water pump had little impact on the overall project economy. Therefore, it can conclude that changes in well status in wells status in an heterogenous hydrocarbon reservoir will increase oil production.

scholarly journals SPECIFICS OF VISCOUS OIL PRODUCTION USING A DRAIN-HOLE WELL

2016 ◽  
pp. 114-119
Author(s):  
I. V. Chizhov
Keyword(s):  
Oil Recovery ◽  
Oil Production ◽  
High Viscosity ◽  
Viscous Oil ◽  
Drain Hole ◽  
High Viscosity Oil

The article is devoted to the problem of increasing the efficiency of high viscosity oil recovery from low permeable beds.

How to Space SAGD Well Pairs for Optimal Performance

2021 ◽  
Author(s):  
Zeinab Zargar ◽  
S. M. Farouq Ali
Keyword(s):  
Oil Recovery ◽  
Moving Boundary ◽  
Late Phase ◽  
Oil Production ◽  
Steam Injection ◽  
Injection Rate ◽  
Analytical Relation ◽  
Oil Sand ◽  
Steam Quality ◽  
Well Spacing

Abstract Steam-Assisted Gravity Drainage (SAGD) is a remarkably successful process for the tar sands (oil sands). Two closely spaced parallel horizontal wells, injector above the producer, form a SAGD well pair. Steam is injected to provide heat to the reservoir oil and mobilize it. The low viscosity oil drains down to the producer under the gravity effect. Parallel well pairs 1000 m long are utilized in the process, spaced 100 m apart horizontally almost in all projects. In this work, an analytical model for the SAGD process is introduced by coupling heat and fluid flow and constitutive equations. A moving boundary, counter-current flow approach is used for the steam chamber rise and subsequent sideways expansion. The model is unique because it assumes the steam injection rate is constant and it permits modeling of the late phase of SAGD when adjacent well pair interference occurs. This leads to a reduction in heat loss to the overburden and a decline in oil production rate. This study examines the question of optimal well pair spacing in relation to the formation thickness and in-place oil. The effect of other variables on SAGD performance is investigated. A case study was performed using Christina Lake oil sand properties to show how the project performance varies under different senerios involving well pair spacing, reservoir thickness, steam injection rate, and steam quality. Results show that, in evaluating a SAGD pad performance, as the spacing is increased, the cumulative oil production decreases, with a simultanous increase in the cumulative steam-oil ratio at the same steam injection rate. However, a smaller portion of injected heat is lost to the overburden. It is concluded that a smaller well spacing requires more wells to deplete the whole pad area. On the other hand, a larger pattern well spacing affects oil recovery and heat consumption. Different conclusions are derived for the same pattern well spacing value using a single well pair model and pattern well pair configuration. Results also show that SAGD well pair spacing can be increased with an increase in formation thickness. The computational procedure is simple and makes it possible to examine a series of options for well spacing for a given set of conditions. This study presents for the first time an analytical relation between SAGD pattern well pair spacing and oil recovery.

scholarly journals Compositions and Co-occurrence Patterns of Bacterial Communities Associated With Polymer- and ASP-Flooded Petroleum Reservoir Blocks

2020 ◽  
Vol 11 ◽  
Author(s):  
Guoling Ren ◽  
Jinlong Wang ◽  
Lina Qu ◽  
Wei Li ◽  
Min Hu ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Bacterial Communities ◽  
Chemical Properties ◽  
Oil Production ◽  
Chemical Flooding ◽  
Petroleum Reservoir ◽  
Promising Alternative ◽  
Asp Flooding ◽  
Production Wells ◽  
Occurrence Patterns

Polymer flooding technology and alkaline-surfactant-polymer (ASP) flooding technology have been widely used in some oil reservoirs. About 50% of remaining oil is trapped, however, in polymer-flooded and ASP-flooded reservoirs. How to further improve oil recovery of these reservoirs after chemical flooding is technically challenging. Microbial enhanced oil recovery (MEOR) technology is a promising alternative technology. However, the bacterial communities in the polymer-flooded and ASP-flooded reservoirs have rarely been investigated. We investigated the distribution and co-occurrence patterns of bacterial communities in ASP-flooded and polymer-flooded oil production wells. We found that Arcobacter and Pseudomonas were dominant both in the polymer-flooded and ASP-flooded production wells. Halomonas accounted for a large amount of the bacterial communities inhabiting in the ASP-flooded blocks, whereas they were hardly detected in the polymer-flooded blocks, and the trends for Acetomicrobium were the opposite. RDA analysis indicated that bacterial communities in ASP-flooded and polymer-flooded oil production wells are closely related to the physical and chemical properties, such as high salinity and strong alkaline, which together accounted for 56.91% of total variance. Co-occurrence network analysis revealed non-random combination patterns of bacterial composition from production wells of ASP-flooded and polymer-flooded blocks, and the ASP-flooded treatment decreased bacterial network complexity, suggesting that the application of ASP flooding technology reduced the tightness of bacterial interactions.

scholarly journals USE OF ELECTROTREATMENT METHOD FOR OIL RECOVERY ENHANCEMENT

2015 ◽  
pp. 67-73 ◽  
Author(s):  
O. V. Smirnov ◽  
A. E. Kozyaruk ◽  
K. V. Kuskov ◽  
A. L. Portnyagin ◽  
A. V. Saphonov
Keyword(s):  
Oil Recovery ◽  
Oil Production ◽  
Well Stimulation ◽  
Viscous Oil

The paper considers the issues of oil production enhancement through applying methods of well stimulation including the wells producing viscous oil, in particular various methods of electrotreatment.

scholarly journals Status Quo of a CO2-Assisted Steam-Flooding Pilot Test in China

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-13
Author(s):  
Zongyao Qi ◽  
Tong Liu ◽  
Changfeng Xi ◽  
Yunjun Zhang ◽  
Dehuang Shen ◽  
...  
Keyword(s):  
Field Test ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Oil Production ◽  
Oil Field ◽  
Drainage Pattern ◽  
Steam Flooding ◽  
Production Wells ◽  
Water Cut ◽  
Production Dynamics

It is challenging to enhance heavy oil recovery in the late stages of steam flooding. This challenge is due to reduced residual oil saturation, high steam-oil ratio, and lower profitability. A field test of the CO2-assisted steam flooding technique was carried out in the steam-flooded heavy oil reservoir in the J6 block of the Xinjiang oil field (China). In the field test, a positive response to the CO2-assisted steam flooding treatment was observed, including a gradually increasing heavy oil production, an increase in the formation pressure, and a decrease in the water cut. The production wells in the test area mainly exhibited four types of production dynamics, and some of the production wells exhibited production dynamics that were completely different from those during steam flooding. After being flooded via CO2-assisted steam flooding, these wells exhibited a gravity drainage pattern without steam channeling issues, and hence, they yielded stable oil production. In addition, emulsified oil and CO2 foam were produced from the production well, which agreed well with the results of laboratory-scale tests. The reservoir-simulation-based prediction for the test reservoir shows that the CO2-assisted steam flooding technique can reduce the steam-oil ratio from 12 m3 (CWE)/t to 6 m3 (CWE)/t and can yield a final recovery factor of 70%.

Experimental Investigation of In-Situ Emulsion Formation To Improve Viscous-Oil Recovery in Steam-Injection Process Assisted by Viscosity Reducer

SPE Journal ◽  
2016 ◽  
Vol 22 (01) ◽  
pp. 130-137 ◽  
Author(s):  
Chuan Lu ◽  
Huiqing Liu ◽  
Wei Zhao ◽  
Keqin Lu ◽  
Yongge Liu ◽  
...  
Keyword(s):  
High Temperature ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Steam Injection ◽  
Viscosity Reduction ◽  
Injection Process ◽  
Viscous Oil ◽  
Viscosity Reducer ◽  
High Temperature Steam

Summary In this study, the effects of viscosity-reducer (VR) concentration, salinity, water/oil ratio (WOR), and temperature on the performance of emulsions are examined on the basis of the selected VR. Different VR-injection scenarios, including single-VR injection and coinjection of steam and VR, are conducted after steamflooding by use of single-sandpack models. The results show that high VR concentration, high WOR, and low salinity are beneficial to form stable oil/water emulsions. The oil recoveries of steamflooding for bitumen and heavy oil are approximately 31 and 52%, respectively. The subsequent VR flooding gives an incremental oil recovery of 5.2 and 6.4% for bitumen and heavy oil, respectively. Flooding by steam/VR induces an additional oil recovery of 8.4–11.0% for bitumen and 12.1% for heavy oil. High-temperature steam favors the peeling off of oil and improving its fluidity, as well as the in-situ emulsions. VR solution is beneficial for the oil dispersion and further viscosity reduction. The coinjection of high-temperature steam and VR is much more effective for additional oil production in viscous-oil reservoirs.

Laboratory Investigation of the Effect of Solvent Injection on In-Situ Combustion

SPE Journal ◽  
2008 ◽  
Vol 13 (02) ◽  
pp. 153-163 ◽  
Author(s):  
Jean Cristofari ◽  
Louis M. Castanier ◽  
Anthony R. Kovscek
Keyword(s):  
Crude Oil ◽  
Oil Production ◽  
Steam Injection ◽  
Northern Coast ◽  
Oil Viscosity ◽  
In Situ Combustion ◽  
Solvent Injection ◽  
Effect Of Solvent ◽  
Viscous Oil

Summary Application of cyclic solvent injection into heavy and viscous crude oil followed by in-situ combustion of heavy residues is explored from a laboratory perspective. The solvent reduces oil viscosity in-situ and extracts the lighter crude-oil fractions. Combustion cleans the near-well region and stimulates thermally the oil production. Both solvent injection and in-situ combustion are technically effective. The combination of the two methods, however, has never been tried to our knowledge. Hamaca (Venezuela) and West Sak (Alaska) crude oils were employed. First, ramped temperature oxidation studies were conducted to measure the kinetic properties of the oil prior to and following solvent injection. Pentane, decane, and kerosene were the solvents of interest. Second, solvent was injected in a cyclic fashion into a 1-m-long combustion tube. Then, the tube was combusted. Hamaca oil presented good burning properties, especially following pentane injection. The pentane extracted lighter components of the crude and deposited preferentially effective fuel for combustion. On the other hand, West Sak oil did not exhibit stable combustion properties without solvent injection, following solvent injection, and even when metallic additives were added to enhance the combustion. We were unable to propagate a burning front within the combustion tube. Nevertheless, the experimental results do show that this combined solvent combustion method is applicable to the broad range of oil reservoirs with properties similar to Hamaca. Introduction This article investigates the effect of solvent injection on the subsequent performance of in-situ combustion. The work is based on experimental results obtained by a combination of these two successful in-situ upgrading processes for viscous oils. It is envisioned that application in the field occurs first by a cycle of solvent injection, a short soak period, and subsequent oil production using the same well (Castanier and Kovscek 2005). By mixing with oil, the solvent decreases the oil viscosity and upgrades the crude by extracting in-situ the lighter ends of the crude oil. The heavy ends, that are markedly less interesting, are left behind. Injection of solvent and oil production occurs for a number of cycles until the economic limit is reached or until the deposition of crude oil heavy ends damages production. The solvent injection phase is followed by in-situ combustion that burns the heavy ends left from the solvent injection. By switching from air to nitrogen injection, the combustion is extinguished. Again, oil is produced by the same well used for injection in a cyclic fashion. Combustion enhances the production by decreasing thermally the oil viscosity and adding energy to the reservoir through the formation of combustion gases. The combustion also upgrades the oil through thermal cracking (Castanier and Brigham 2003). For our experiments, two oils of particular interest were used. The first experiments employed crude oil from Hamaca (Venezuela), where the field location requires important costs of transporting crude to upgrading facilities. The second set of experiments was conducted with viscous West Sak oil (Alaska), where steam injection currently appears to be unsuitable because of heat losses to permafrost. While the presence of oil in the Orinoco heavy-oil belt, in Central Venezuela, was discovered in the 1930s, the first rigorous evaluation of the resources was made in the 1980s, and the region was divided into four areas: Machete, Zuata, Hamaca, and Cerro Negro. It contains between 1.2 and 1.8 trillion recoverable barrels (Kuhlman 2000) of heavy and extra-heavy oil. The 9-11° API density crude is processed at the Jose refinery complex on the northern coast of Venezuela. The cost of transporting heavy oils to the northern coast provides an incentive to investigate in-situ upgrading. In 2003, the total production from these projects was about 500,000 B/D of synthetic crude oil. This figure was expected to increase to 600,000 B/D by 2005 (Acharya et al. 2004). West Sak is a viscous oil reservoir located within the Kuparuk River Unit on the North Slope of Alaska. It is part of a larger viscous oil belt that includes Prudhoe Bay. The estimated total oil in place ranges from 7 to 9 billion barrels, with an oil gravity ranging from 10 to 22°API. The reservoir depth ranges from 2,500 to 4,500 feet, with gross thickness of 500 feet and an average net thickness of 90 feet. The temperature is between 45 and 100°F, and there is a 2,000-ft (600-m) -thick Permafrost layer. In March 2005, 16,000 BOPD were produced and 40,000 BOPD are planned for 2007 (Targac et al. 2005). Within the scope of this study, West Sak is of particular interest because there are technical difficulties with steam injection that include (Gondouin and Fox 1991):Surface-generated steam passing through a thick permafrost layer; the well would sink if the permafrost melted.The reservoirs consist of thin, medium-permeability layers.The formation may contain swelling clays that reduce the rock permeability when exposed to steam condensate. Solvent injection and in-situ combustion are effective in a variety of fields. Both techniques upgrade the oil directly in the reservoir, thereby making heavy resources easier to exploit. The combination of these two processes is applicable at large scale to recover viscous oil, or in-situ combustion could be applied on an ad hoc basis to clean the wellbore region, increase the permeability, and thus act as a stimulation process.

scholarly journals Impact of physical phenomena and cyclical reinjection in miscible CO2-WAG recovery in carbonate reservoirs

2020 ◽  
Vol 10 (8) ◽  
pp. 3865-3881
Author(s):  
Marcio Augusto Sampaio ◽  
Samuel Ferreira de Mello ◽  
Denis José Schiozer
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Oil Production ◽  
Aqueous Solubility ◽  
Carbonate Reservoirs ◽  
Recovery Techniques ◽  
Salt Cluster ◽  
Physical Phenomena

Abstract Carbonated reservoirs with high percentage of CO2 have been discovered and produced in the Brazilian pre-salt cluster. Recovery techniques, such as CO2-WAG, have hence been evaluated and applied, as in the Lula field. Although studies demonstrate the advantages of this technique, it is still difficult to estimate an increase in oil recovery. Thus, this work presents a methodology to evaluate the impacts of the main phenomena that occur and how CO2 recycling can benefit the management of these fields. The results showed an increase in recovery with the modeling of the main phenomena such as relative permeability hysteresis and aqueous solubility of CO2, accompanied by a significant increase in CO2 injection. However, the recycling of the CO2 produced was shown to be fundamental in the reduction in this injection and to increase the NPV. The results showed a 4% increase in oil production and 9% in NPV, considering a producer–injector pair.

scholarly journals VARIATION OF CARBON SOURCES IN PRODUCTING RHAMNOLIPID BY Pseudomonas aeruginosa FOR MICROBIAL ENHANCED OIL RECOVER�S APPLICATION (VARIASI SUMBER KARBON PADA PRODUKSI RHAMNOLIPID OLEH Pseudomonas aeruginosa DALAM APLIKASI MICROBIAL ENHANCED OIL RECOVERY (MEOR))

2018 ◽  
Vol 40 (1) ◽  
pp. 33-40
Author(s):  
Nafian Awaludin ◽  
Cut Nanda Sari
Keyword(s):  
Pseudomonas Aeruginosa ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Carbon Sources ◽  
Oil Production ◽  
Waste Cooking Oil ◽  
Microbial Enhanced Oil Recovery ◽  
Interface Tension ◽  
Cooking Oil ◽  
Production Wells

The decrease in oil production is caused by the ageing of oil production wells. The enhanced oil recovery (EOR) technology is proven to increase oil reserves and production in mature oil fields. One EOR technology that has proven to be efficient in increasing oil production is microbial EOR by using biosurfactant. The most effective biosurfactant is rhamnolipid produced by Pseudomonas aeruginosa, the bacteria of which can lower the interfacial tension between the petroleum and water. In biosurfactants production thanks to these bacteria, the substrate as the source of carbon in the fermentation process is needed. The sources of carbon used in this study are glucose, glycerol, molasses, banana peels, and waste from Pseudomonas aeruginosa by using Busnell Hass medium as a liquid medium of bacterial growth. Biosurfactants production results are; 74mg/L from glucose; 63mg/L from banana peels; 66mg / L from glycerol; 85mg/L from waste cooking oil; and 64mg/L of molasses with the following decreasing surface tension: 33.55 mN/m from glucose; 32.51 mN/m from banana peels; 27.55 mN/m from glycerol; 22.46 mN/m from waste cooking oil; and 31.49 mN/m from molasses. In addition, the decrease of interface tension of glucose; banana peels; glycerol; waste cooking oil; and molasses are as follows : 15.2 mN/m; 13.78 mN/m; 8:15 mN/m; 0.14 mN/m; and 11.2 mN/m respectively.Menurunnya produksi minyak bumi disebabkan karena sumur produksi yang sudah tua. Teknologi enhanced oil recovery (EOR) terbukti mampu meningkatkan cadangan dan produksi lapangan minyak mature. Salah satu teknologi EOR yang dikenal efi sien dalam meningkatkan perolehan minyak adalah microbial enhanced oil recovery menggunakan biosurfaktan. Biosurfaktan yang paling efektif adalah rhamnolipid yang dihasilkan oleh bakteri Pseudomonas aeruginosa yang dapat menurunkan tegangan antarmuka antara minyak bumi dengan air. Dalam produksi biosurfaktan oleh bakteri ini, diperlukan substrat sebagai sumber karbon dalam proses fermentasi. Sumber karbon yang digunakan pada penelitian ini adalah glukosa, gliserol, molase, kulit pisang, dan minyak jelantah. Penelitian ini bertujuan untuk mengetahui sumber karbon yang paling optimum dalam menghasilkan biosurfaktan dari Pseudomonas aeruginosa dengan menggunakan busnell hass medium sebagai media cair pertumbuhan bakteri. Produksi biosurfaktan yang dihasilkan adalah 74mg/L dari glukosa; 63mg/L dari kulit pisang; 66mg/L dari gliserol; 85mg/L dari minyak jelantah; dan 64mg/L dari molase dengan penurunan tegangan permukaan berturutturut: 33,55 mN/m dari glukosa; 32,51 mN/m dari kulit pisang; 27,55 mN/m dari gliserol; 22,46 mN/m dari minyak jelantah; dan 31,49 mN/m serta memiliki penurunan tegangan antarmuka dari glukosa; kulit pisang; glisero; minyak jelantah; dan molase berturut-turut adalah 15,2 mN/m; 13,78 mN/m; 8,15 mN/m; 0,14 mN/m; dan 11,2 mN/m.

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