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Ahmed, A. Alsubaih (Basra oil company) | Hayfaa, L. Swadi (Basrah University) | Nuhad, Alkanaani (Basrah University) | Erfan, M. Al lawe (Basra oil company) | Ahmed, I. Aljarah (Basra oil company) | Swadi, Madhi (Basra oil company) | Tariq, K. Khamees (Missouri University of Science & Technology)
ABSTRACT: The directional dependency of the rock strength parameters (Elastic Anisotropy) is a key factor to be considered during the construction of a geomechanical model to ensure safer drilling operations (especially directional drilling). Since the geomechanical model prediction is greatly affected by the magnitude of the rock strength parameters thus it should be involved in wellbore stability investigation. Determination of the degree of anisotropy can be measured by several approaches, one of which is using elastic waves. In this study, the compressive strength of the rocks from several formations (Tanuma, Khasib, Sadi, and Mishrif), in southern Iraq was estimated using measurements from advanced sonic log that was calibrated by the static measurements of the rock strength. The Tanuma shale formation showed directional dependency behaver of rock stresses while the rock strength was less sensitive to the investigation angle. Therefore, the effect of the degree of anisotropy and the well inclination on the wellbore failure was examined. By including the strength anisotropy effect to the geomechanical model, the appropriate drilling fluid density has been proposed based on the well inclinations and angles. It can be observed that; this effect is more prone when the well azimuth is in direction or close to the maximum principal stress direction. On the other hand, the well is more stable (in terms of shear failure) when it is drilled in the direction of least principal stress. The optimum well trajectory should be around 45 degrees from maximum horizontal stress. Hence, the fluid density has been adjusted with respect to well trajectory parameters to mechanically stabilize the wellbore.
Rock anisotropy effect induces wellbore stability problems especially in deviated and horizontal wells. Clearly, the mechanical properties of certain kinds of rocks are directionally dependent. These properties are; Young Modulus, Poisson ratio, shear, and tensile strength (Aadnoy et al., 2010). In other words, these directionally dependent parameters might be relatively higher in specific directions, yet it relatively lower in others. These variations in the properties can be induced by several shear and tensile failure during highly deviated well penetration. In this regard, the plane of weakness being introduced in geomechanics studies of the wellbore stability that proposes there is a weak plane in which the rock fails under specific circumstances (Jaeger & Cook, 2007). Occasionally, the rock failure more likely takes places along this plane rather than cross to it. In the lab scale, it is encountered during core sample analysis when the angle between the applied force vector and the formation bedding is not too high. Thus, the severity of the bedding related failure is based on; the wellbore attack angle on the bedding planes, the normal stresses around the wellbore, formation dipping and wellbore azimuth (Aadnoy et al., 2009; Wu & Tan, 2010; Økland & Cook, 1998; Shamsuzzoha, 2015).
Khamees, Tariq K. (Missouri University of Science & Technology) | Flori, Ralph E. (Missouri University of Science & Technology) | Alsubaih, Ahmed A. (Basra Oil Company) | Alhuraishawy, Ali K. (Missan Oil Company)
In-depth gel treatment is a chemical EOR process used to improve the sweep efficiency from heterogeneous reservoirs with crossflow. However, if these reservoirs are saturated with viscous oil, polymer and surfactant flooding should be combined with in-depth gel treatment. Thus, in this study, a 3D model using the UTGEL simulator was built to model in-depth gel treatment combined with surfactant slug and polymer solution. The model was represented by one quarter of the five-spot pattern with eight layers where two thief zones are located in the middle of the model. The thief zones had a permeability of 1500 md with a total thickness of 20 ft, while the rest of the layers had a permeability of 100 md with a total thickness of 200 ft.
The gel system consisted of a polyacrylamide/Cr(VI)/thiourea solution, which is considered an in-situ gelation system. Gelant solution was injected for 60 days when the water cut in the model reached 65%, followed by surfactant slug for 2 years, polymer solution for 3 years, and then post-water injection for the rest of the simulation time. The concentrations of the surfactant ranged from 0.01 to 0.2 wt.%, while the polymer concentration was 1,000 ppm. The injection rate was 1,070 bbl/day during all flooding and treatment processes.
The results showed that it is imperative to implement surfactant with gel treatment to reduce the interfacial tension between water and oil phases and to alter the wettability of the reservoir rocks. Thus, gel treatment alone or gel followed by polymer was not as efficient as the injection of a surfactant slug. The results also showed that as the reservoir temperature increased, the overall performance of gel, polymer, and surfactant decreased. Therefore, the higher the temperature, the lower the recovery factor. The results also revealed the importance of viscoelastic behavior of the HPAM polymer solution where higher results for both water-wet and oil-wet conditions were obtained compared to shear-thinning behavior only. Moreover, the results revealed interesting behavior regarding the concentration of the surfactant, where the recovery factor increased as the concentration of the surfactant increased in oil-wet conditions. However, in water-wet conditions, the results were unpromising and unfavorable. Furthermore, the injection of surfactant directly after the gel treatment was more effective in improving the sweep efficiency than the injection of polymer directly after the gel treatment. Finally, as the salinity of makeup water and/or reservoir brine increased, the recovery factor decreased for both water and oil-wet systems. This is because, as salinity increased, the adsorption of both polymer and surfactant increased and the polymer viscosity decreased. Furthermore, the presence of divalent cations such as Ca+2 and Mg+2, would have a negative impact on overall treatment.
This study presents a numerical modeling of a sodium silicate gel system (inorganic gel) to mitigate the problem of excess water production, which is promoted by high heterogeneity and/or an adverse mobility ratio. A numerical model of six layers was represented by one quarter of five spot pattern with two thief zones. CMG-STARS simulator was used that has the capabilities of modeling different parameters. The gelation process of this gel system was initiated by lowering the gelant's pH, and then the reaction process proceeded, which is dependent on temperature, concentration of the reactant, and other factors. An order of reaction of each component was determined and the stoichiometric coefficients of the reactants and product were specified. The purpose of this study is to develop a thorough understanding of the effects of different important parameters on the polymerization of a sodium silicate gel system.
This study was started by selecting the optimum gridblock number that represents the model. A sensitivity analysis showed that the fewer the number of gridblocks, the better the performance of the gel system. This model was then selected as a basis for other comparisons. Different scenarios were run and compared. The results showed that the gel system performed better in the injection well compared to the production well. In addition, the treatment was more efficient when performed simultaneously in injection and production wells. Placement technology was among the parameters that affected the success of the treatment; therefore, zonal isolation and dual injection were better than bullhead injection. Lower activator concentration is more preferable for deep placement. Pre-flushing the reservoir to condition the targeted zones for sodium silicate injection was necessary to achieve a higher recovery factor. Moreover, different parameters such as adsorption, mixing sodium silicate with different polymer solutions, effects of temperature and activation energy, effects of shut-in period after the treatment, and effects of reservoir wettability were investigated. The obtained results were valuable, which lead to apply a sodium silicate gel successfully in a heterogeneous reservoir.
ABSTRACT: Drilling fluid invasion into shales is one reason for instabilities while drilling. Invaded drilling fluid affects near wellbore stresses, rock strength, and overbalance wellbore pressure. The fluid invasion is a coupled-transport phenomena mainly due to hydraulic drive and chemical potential drive. The invaded fluid will increase near wellbore pore pressure and reduce effective stresses, therefore the likelihood of wellbore instabilities arise. The flow of fluid through shales’ pores and micro fractures should be mitigated using an effective additives in a water-based drilling fluid system. This paper will experimentally evaluate using of Combusted Carbon Residuals (CCRs) as a shale inhibitor additive. Combusted Carbon Residuals were mechanically grinded. Pressure transient testing was used to evaluate CCRs in a water-based drilling fluid system for controlling fluid invasion into Catoosa shale samples. Also, two chemically made nano silica, AEROSIL & AERODISP were tested in comparison to fine grained CCRs. The testing results shows the positive impact of using fine grained CCRs in controlling fluid invasion rate compared to the conventional water based drilling fluid and the two other nano products were tested.
Time-dependent drilling fluid invasion in shales causes wellbore instabilities [1-7]. Fluid invasion in shales is believed to be a physiochemical process mainly due to hydraulic potential drive and chemical potential drive [6, 8]. The Darcy flow of water is driven by hydraulic potential gradients (pressure imbalance), and diffusion of solutes are driven by chemical potential gradients (chemical imbalance) between the drilling fluid and the shales’ pore fluid. Increase of near wellbore pore pressure, reduction of near wellbore rock strength, increase of hydration stress in pore space, and shales swelling or wellbore size shrinkage are the main consequences of shale hydration [3, 9, 10]. Invaded drilling fluid increases pore pressure since shales have a low permeability and cannot dissipate excess pore pressure [1, 2, 6, and 7]. The shale hydration causes differential micro-strains and weakens the cohesive bonds between clay platelets which results in strength reduction . There are different theories that have been developed to describe the shales swelling process, such as hydraulic pressure balance, capillary suction (surface hydration), and osmosis pressure [6, 8, 12]. However, shales swelling phenomena is not well-understood and there is no agreement as to which mechanism is dominant in the shale hydration.
Copyright 2018, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Hydraulic Fracturing Technology Conference & Exhibition held in The Woodlands, Texas, USA, 23-25 January 2018. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.
Ma, Liping (Research Institute of Oil and Gas Technology, Changqing Oilfield, Petrochina) | Wang, Shitou (Research Institute of Oil and Gas Technology, Changqing Oilfield, Petrochina) | Long, Yifu (Missouri University of Science & Technology) | Zhu, Changqian (Missouri University of Science & Technology) | Yang, Hongbin (China University of Petroleum ) | Yang, Tangying (Research Institute of Oil and Gas Technology, Changqing Oilfield, Petrochina) | Liu, Xiaochun (Research Institute of Oil and Gas Technology, Changqing Oilfield, Petrochina) | Li, Xiaorong (Research Institute of Oil and Gas Technology, Changqing Oilfield, Petrochina) | Bai, Baojun (Missouri University of Science & Technology) | Kang, Wanli (China University of Petroleum)
In order to address the conformance problem in high temperature and high salinity/hardness reservoir, an environmentally benign in-situ gel was developed based on hydrolyzed polyacrylamide (HPAM) and polyethyleneimine (PEI). Moreover, silica nanoparticle (SNP) was embedded to improve the performance of HPAM/PEI gel. To achieve the optimum formulation of HPAM/PEI-SNP gel, a comprehensive investigation was first conducted with the respect of gelation time, gel strength, and thermal stability. In addition, the particle size of SNP was determined by Dynamic Light Scatter (DLS) and the microstructure of HPAM/PEI-SNP gel was characterized via Scanning Electron Microscopy (SEM).
The optimum formulation, containing the polymer/crosslinker ratio of 10,000-2,000 using high molecular weight HPAM (10-15 million Dalton) with a low hydrolysis degree of 3-7%, was obtained. Given the compatibility of comparability of SNP and formation water, LS nano silica with an SNP concentration of 30 wt% was selected as hybrid resource. The results indicated that the gelation time of novel gel system was prolonged to 132 hours attributed to the introducing of nanomaterial. Taking advantage of nano-composite, the strength of HPAM/PEI-SNP gel maintained as Grade G for 312 h. Furthermore, the HPAM/PEI-SNP gel exhibited an excellent thermal stability at 85 °C for 660 hours without syneresis. Subsequently, SEM images confirmed the successful incorporation of SNP in the 3-dimentional network of hydrogel, supporting an effective surface modification.
This work demonstrated that the novel environmentally benign HPAM/PEI-SNP gel system can be used as a potential plugging agent for the conformance improvement in high temperature high salinity reservoirs.
Mohammed, Omar Q. (North Oil Company) | Kassim, Rashid (Missouri University of Science & Technology) | Britt, Larry K. (NSI Fracturing LLC) | Dunn-Norman, Shari (Missouri University of Science & Technology)
The Montney Formation which stretches from Alberta to British Columbia is one of the largest unconventional gas resources in North America. Production from the Montney Formation comes primarily from the Upper Montney and Lower Montney Formations which vary both from reservoir quality and geomechanical perspectives. Historically, completion and stimulation optimization fell into two distinct categories (1) field observation supported by reservoir and fracture simulation or (2) statistical analysis. Few, if any, statistical studies on optimizing unconventional completions and fracture stimulation combined information from the statistical analysis with that of the simulation. This paper does just that for the Montney Formation by comparing and contrasting the Upper and the Lower Montney completions and fracture stimulation statistical results with a reservoir and fracture simulation study to better understand key drivers for successful stimulation of multiple fractured horizontal wells.
Previous work (
This study investigated fracture performance to find the best fracturing practices for the Upper and the Lower Montney. This wok benefits the industry by: Providing a solid simulation study of horizontal gas wells with cased-hole completion, which compared fracture performance for the Upper and the Lower Montney Formation. Providing comparison of multiple fractured horizontal wells' performance in the Upper and the Lower Montney Formation based on the number of clusters per stage and treatment volume. Identifying factors that affect cased-hole completions and stimulation performance in the Upper and the Lower Montney Formation. By conducting fracture cluster optimization study to determine the effect of the number of clusters, cluster spacing and proppant type on fracture dimensions and well performance.
Providing a solid simulation study of horizontal gas wells with cased-hole completion, which compared fracture performance for the Upper and the Lower Montney Formation.
Providing comparison of multiple fractured horizontal wells' performance in the Upper and the Lower Montney Formation based on the number of clusters per stage and treatment volume.
Identifying factors that affect cased-hole completions and stimulation performance in the Upper and the Lower Montney Formation.
By conducting fracture cluster optimization study to determine the effect of the number of clusters, cluster spacing and proppant type on fracture dimensions and well performance.
Mohammed, Omar Q. (North Oil Company) | Kassim, Rashid (Missouri University of Science & Technology) | Britt, Larry K. (NSI Fracturing LLC) | Dunn-Norman, Shari (Missouri University of Science & Technology)
The Montney Formation which extends from Alberta to British Columbia is one of the largest unconventional gas resources in North America. Production from the Montney Formation comes primarily from the Upper Montney and Lower Montney Formations which vary both from reservoir quality and geomechanical perspectives. Historically, completion and stimulation optimization fell into two distinct categories (1) field observation supported by reservoir and fracture simulation or (2) statistical analysis. Few, if any, statistical studies on optimizing unconventional completions and fracture stimulation combined information from the statistical analysis with that of the simulation. This paper does just that for the Montney Formation by comparing and contrasting the Upper and the Lower Montney completions and fracture stimulation statistical results with a reservoir and fracture simulation study to better understand key drivers for successful stimulation of multiple fractured horizontal wells.
Previous work (Mohammed et al., 2016) documented the statistical analysis of 296 cased-hole horizontal gas wells’ completions in the Upper and the Lower Montney Formation. The study showed the effect of cased-hole completion and stimulation parameters on gas production performance in both the Upper and the Lower Montney Formations. In this paper, previous statistical results were extended by adding hydraulic fracture modeling using 3D finite element simulator (Stimplan3D). The results from the statistical analysis and hydraulic fracture modeling were compared on a set of parameters such as the effect of the number of clusters per stage (1-to-5), changes in proppant mass (50% decrease or increase) and treatment volumes.
This study investigated fracture performance to find the best fracturing practices for the Upper and the Lower Montney.
In-depth gel treatment has become an attractive and optimum technology for remedying any problems that cause poor sweep efficiency, such as heterogeneity of the reservoir and unfavorable mobility ratio (due to high oil viscosity). The low recovery factor resulted from the difference in reservoir properties especially reservoir permeability, would lead eventually to use of the chemical materials such as polymer and gel to correct this condition. A comprehensive simulation study of deep placement of weak gel in thick heterogeneous reservoir is presented in this paper. A conceptual model with quarter of inverted nine spot pattern using CMG-STARS commercial simulator was built, to demonstrate the effectiveness of in-depth gel treatment in correcting the heterogeneity in this thick reservoir. The model consists of one injector and three producers with three layers of different permeabilities and thicknesses. These wells are perforated in all layers of the model (i.e., layers 1, 2, & 3).
The results showed that injecting even a low PV of gel into high permeability layers could make a remarkable increase in oil recovery factor and incremental oil over the base case water flooding. Polymer and gel degradation rate have a significant impact on the reservoir performance after the treatment. Three different scenarios for both polymer and gel degradation are considered: no degradation, 2 years and 4 years degradation. The results were showed that always the runs without degradation yielded higher recovery factor regardless the injected PV. In addition, when gel is injected into only high permeability layers a higher incremental oil and higher oil recovery factor were obtained in comparison with runs when gel is injected into all three layers. Moreover, the more homogeneous the reservoir is, the higher recovery factor could be obtained. However, in this study, changing the crossflow (kv/kh) value has no effect on oil recovery values over the ranges selected (i.e., 0.001, 0.005, 0.01, and 0.02). The best time to start gel injection is also investigated, it was revealed that it is better to start gel treatment when water cut is about 80%, because before that time the high permeability layers may still contain a moveable oil that can be recovered. Another set of runs were carried out to show the importance of injecting polymer and gel together. The results showed that when gel is injected into all three layers with 4 years gel degradation and 2 years polymer degradation, polymer flooding then gel treatment yielded better results than gel treatment then polymer flooding. Finally, a sensitivity analyses, by CMG-CMOST, was carried out to show the importance of in-situ parameters (i.e., k1, k2, k3, kv/kh, RRFT, and thicknesses of the layers) and operating parameters (i.e., polymer properties, injection pressure, and injection time) on cumulative oil production and oil recovery factor. An optimum values have been obtained that yielded the highest cumulative oil production and highest oil recovery factor. All gel treatment runs had been compared with water and polymer flooding to evaluate the diversion potential of in-depth gel treatment.
The Lower Triassic Montney Formation produces from the Western Canadian Sedimentary Basin. This shale play is extensive as it covers nearly 57,000 square miles. The play consists of landing intervals in the Lower, Middle, and Upper Montney Formation for which the oil and gas industry uses multiple fractured horizontal well completions to recover natural gas. Both cased and open hole completions are utilized in the Montney Formation. Identifying the key drivers for success of multiple fractured horizontal wells is not straightforward, especially in unconventional reservoirs like the Montney.
One study by
This work documents the statistical analysis of 296 cased-hole horizontal gas well completions in the Upper and Lower Montney. The work extends the previous statistical study of Montney completions by focusing on cased hole completions, including completion cluster information, and examining the performance of Upper and Lower Montney completions separately.
Results of this analysis show that cumulative gas production per cluster decreases as more perforation clusters are placed in both the Upper and Lower Montney. The study demonstrates that the cumulative gas production per cluster and initial gas production (IP) is higher for the Upper Montney Formation than the Lower Montney Formation.
This work benefits the industry by:
Providing a more focused statistical analysis of horizontal gas well cased hole completion performance in the Montney, compared to recent literature documenting industry practices. Identifying a maximum recommended liquid per cluster amount for completions in the Montney Formation. Providing a comparison of Upper and Lower Montney cased hole completion performance.
Providing a more focused statistical analysis of horizontal gas well cased hole completion performance in the Montney, compared to recent literature documenting industry practices.
Identifying a maximum recommended liquid per cluster amount for completions in the Montney Formation.
Providing a comparison of Upper and Lower Montney cased hole completion performance.