Abstract:Wellbore fluid flow profiles in both producers and injectors tend to change over time due to preferential depletion, formation damage, cross-flow, channelling or tubing or casing leaks. These changes can result in excess water production through channelling, coning, non-uniform water breakthrough (fingering) or out-of-zone injection – all leading to uneven flow, pressure and sweep profiles. Ignoring these complications can result in missing key points on reservoir behaviour, selecting wrong units for a 3D full… Show more
“…Some fraction of the oil in place is bypassed through the movement from reservoir to the wellbore and can not be recovered to the surface. In fi ll drilling in areas where sifnifi cant amount of oil is trapped can be successful method of recovering these amounts of oil from the reservoir (Aslanyan et al, 2014;Awaad et al, 2015;Urban et al, 2016;Parihar et al, 2016). Recovery with CO 2 gas injection was investigated.…”
Oil recovery from the reserevoirs is devided into three stage of primary, secondary and tertiary stage. Primary recovery is done using the antural energy of the reservoir, while the secondary recovery occures after the primary recovery. It ususlly consists of water and gas injection into the reservoirs for improving the oil recovery. Finally, tertiary ecovery takes in place, which is consists of different methods that are after the secondary recovery. The purpose of this paper is to investigate and compare different gas injection scenarios in an Iranian oil reservoir using Eclipse 300 software. It models recovery factor, cumulative recovery, and the effective parameters of gas injection during different procedures of CO 2 gas injection and Water Alternating gas (WAG) injection. Recovery factor, cumulative recovery, remaining oil saturation, and reservoir pressure are studied and compared during different CO 2 gas injection and WAG injection scenarios to specify an optimized pattern of injection process for EOR purpose. Laboratory data of reservoir rock and fl uid are matched by using PVTi software and the results imported into Eclipse for modeling miscible CO 2 injection and WAG injection. The results showed that oil recovery and remaining oil saturation during WAG injection in reservoir are 31.8 and 56.6% and during miscible CO 2 injection are 25.8 and 60.4% respectively. In case if WAG injection is highly suggested instead of miscible CO 2 injection.
“…Some fraction of the oil in place is bypassed through the movement from reservoir to the wellbore and can not be recovered to the surface. In fi ll drilling in areas where sifnifi cant amount of oil is trapped can be successful method of recovering these amounts of oil from the reservoir (Aslanyan et al, 2014;Awaad et al, 2015;Urban et al, 2016;Parihar et al, 2016). Recovery with CO 2 gas injection was investigated.…”
Oil recovery from the reserevoirs is devided into three stage of primary, secondary and tertiary stage. Primary recovery is done using the antural energy of the reservoir, while the secondary recovery occures after the primary recovery. It ususlly consists of water and gas injection into the reservoirs for improving the oil recovery. Finally, tertiary ecovery takes in place, which is consists of different methods that are after the secondary recovery. The purpose of this paper is to investigate and compare different gas injection scenarios in an Iranian oil reservoir using Eclipse 300 software. It models recovery factor, cumulative recovery, and the effective parameters of gas injection during different procedures of CO 2 gas injection and Water Alternating gas (WAG) injection. Recovery factor, cumulative recovery, remaining oil saturation, and reservoir pressure are studied and compared during different CO 2 gas injection and WAG injection scenarios to specify an optimized pattern of injection process for EOR purpose. Laboratory data of reservoir rock and fl uid are matched by using PVTi software and the results imported into Eclipse for modeling miscible CO 2 injection and WAG injection. The results showed that oil recovery and remaining oil saturation during WAG injection in reservoir are 31.8 and 56.6% and during miscible CO 2 injection are 25.8 and 60.4% respectively. In case if WAG injection is highly suggested instead of miscible CO 2 injection.
“…In such situations, infill drilling with closer spacing is an attractive option to enhance reservoir access that accelerates oil production with more strings and at the same time; it has a chance to improve the oil recovery by increasing water swept volume. In other words, infill drilling targets un-swept oil between the wells that used to be bypassed due to heterogeneity (Aslanyan et al 2014).…”
Section: Prize Of Infill Drillingmentioning
confidence: 99%
“…The reservoir fluid flow performance changes for both the injectors and the producers over the time with the maturity of any reservoir due to preferential depletion, formation damage, crossflow, etc., but all of these factors are subjective to the heterogeneity distribution in any specific reservoir (Aslanyan et al 2014). Infill drilling is the most commonly adopted industry practice for several decades because most of the reservoirs around the world are not homogeneous (Driscoll 1974).…”
This paper presents an assessment of infill drilling opportunities in a complex multi-layered heterogeneous carbonate formation located in Abu Dhabi offshore. The subject field was developed last century and is currently undergoing further development with line drive horizontal wells. The field is being redeveloped for improved oil recovery at higher production rates with long horizontal wells. An infill assessment process is defined using sector model reservoir simulations for the specific reservoir. Reservoir simulations are performed on pattern sector models to establish the optimum grid for infill evaluation. Also, the models with an appropriate grid size are used to optimize infill placement (vertical and lateral well placement) and infill drilling timing for a couple of geologically similar areas. In the second step, the sector model results are applied to test the full-field infill development plan. The relatively homogeneous geological area shows very uniform displacement with 1-km spaced wells and gives no considerable benefit of incremental recovery through infill drilling. However, in a comparatively heterogeneous geological area, considerable incremental oil recovery is quantified. In brief, this paper presents a detailed infill drilling and well placement assessment process workflow for the re-development of a multi-layered heterogeneous reservoir.
“…The exact identification of water sources is a crucial step in any further well remedial work to reduce or eliminate them from oil producing wells. [2] …”
Understanding of fluid movement in and near the wellbore is a crucial factor for effective reservoir management including successful remedial actions and field development planning. One of the key objectives in well surveys is to detect and locate sources of fluid flows behind multiple pipe barriers. The conventional Production Logging Tool (PLT) is run to detect fluid flow and identify the type of fluid under downhole conditions, but is limited to measurements only inside the wellbore. Similarly, other diagnostic techniques, such as cement bond logging, give insight only into the cement integrity and also have limited capabilities to detect cross flows behind casing.Recent developments in temperature and noise logging tools and advanced interpretation techniques have provided higher resolution and sensitivity, enabling the detection of previously undetectable leaks and fluid flow behind casing [1].In the present case, a water zone has been identified in a producing formation with High Precision Temperature (HPT) logging and Spectral Noise Logging (SNL) followed by advanced numerical temperature modelling using the TermoSim software application. SNL identifies flowing zones and differentiates between rock-matrix and fracture flows, and TermoSim then numerically models heat exchange between the wellbore fluid and the surrounding rocks and reservoirs. The resulting model quantifies fluid production from each reservoir unit. Conventional production logging (PLT) locates fluid entry points in the wellbore. The integrated HPT-SNL and PLT logging suite can trace the entire water path from the reservoir into the wellbore. This paper describes water source identification by an HPT-SNL-PLT logging suite deployed in several production wells of a Kuwait oil field. In some of the wells in this field, it has been found that water encroached into the perforations from a watered reservoir below through a channel behind the casing. In other wells, it has been found that cold water breakthrough occurred laterally from nearby water injectors. The exact identification of water sources is a crucial step in any further well remedial work to reduce or eliminate them from oil producing wells. [2]
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