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Zeng, Lingping (Curtin University) | Iqbal, Muhammad Atif (Curtin University) | Reid, Nathan (CSIRO) | Lagat, Christopher (Curtin University) | Hossain, Md Mofazzal (Curtin University) | Saeedi, Ali (Curtin University) | Xie, Quan (Curtin University)
Megalitres of water with associated dissolved oxygen are injected into shale reservoirs during the hydraulic fracturing process. Pyrite oxidation, if it occurs
The spontaneous imbibition tests show that the salinity of fluids in ambient conditions is higher than the limited or vacuumed saturation fluids, confirming that pyrite oxidation generates H+ which would dissolve minerals such as calcite and dolomite. This result is also supported by the observed pH and the concentration of dissolved Ca2+. The fluid fully saturated with O2 has the lowest pH and highest Ca2+ compared to limited O2 saturation condition and degassed condition. Scanning electron microscopy analyses show that brine saturation barely affects the morphology and elemental distribution of pyrite at ambient conditions, suggesting that pyrite oxidation plays a minor role in fluid salinity. Geochemical modelling also indicates that although pyrite oxidation can slightly increase fluid salinity, the salinity increment is less than 5% of reported flowback water salinity, confirming that the dissolved O2 in hydraulic fracturing fluids has a minor effect on fluid-rock interaction thus the salinity increment. This work demonstrates that pyrite dissolution at lab-scale would overestimate the impact of fluid-shale interactions and calcite dissolution in reservoir conditions. We prove that pyrite dissolution in
Multiple attempts to commercially produce from a horizontal well in a challenging sandstone formation completed with the plug-and-perf method were rendered unsuccessful. An innovative stimulation strategy was proposed for the next candidate in an attempt to improve post-fracturing productivity. Three different types of proppant fracturing treatments were performed as a first-time application, including hybrid slickwater treatment, low-guar crosslinked treatment, and CO2 foam fracturing.
A hybrid design combining high-rate slickwater at the beginning and low-guar-loading crosslinked gel at the end of the treatment was pumped in two stages. This allowed minimizing the crosslinked fluid pumped while enhancing fracture half-length. Second, conventional low-guar fracturing was implemented in four stages. Crosslinked gel loading was reduced by 25% compared to gel that was utilized in offset wells. Finally, a CO2 foam fracturing design with a novel biopolymer linear fracturing fluid was implemented in the last stage. This reduced water consumption and improved the chance of increased gas production by yielding a higher-conductivity fracture network.
Friction pressure for CO2 foam was calibrated using bottomhole gauge data that was obtained with downhole gauges run prior to the calibration testing. The new calibrated friction numbers were then used for the bottomhole treating pressure calculation during the treatment. CO2 foam fracturing was found to be a significant success for this well based on multiple evaluation criteria. First, the use of foam helped conserve 1,000 bbl of freshwater compared to conventional stages. Second, the foam treatment allowed two times faster cleanup compared to other stages, based on cleanup time normalized over fluid volumes. Finally, production logging results showed that the foamed treatment achieved better production compared to other treatments in the well, considering productivity index (PI) normalized by the proppant mass, porosity, and zone mobility. The CO2 stage normalized PI was significantly higher than the other stages in the well. After the well was cleaned up, a production log was conducted, and it was analyzed to corroborate the higher production: 70% of the production contribution was seen from the CO2 treatment interval.
In most of the literature, estimates of the friction correlations for foams are based on empirical data. This paper gives the calculations of friction pressure based on field data. The combination of measured bottomhole data and post-cleanup production logging demonstrates the potential productivity improvements that can be achieved through novel design approaches. This type of data is rare in the industry and can help to improve the design of foamed fracturing treatments.
Liu, Huifeng (PetroChina Tarim Oilfield Company) | Li, Jiaxue (China University of Petroleum, Beijing @Keramay) | Xu, Zhixiong (PetroChina Tarim Oilfield Company) | Yuan, Zebo (PetroChina Tarim Oilfield Company) | Liu, Jv (PetroChina Tarim Oilfield Company) | Ren, Dengfeng (PetroChina Tarim Oilfield Company) | Feng, Jueyong (PetroChina Tarim Oilfield Company)
The method of micro-sized graded proppant injection has been proposed in the industry to increase the size of the stimulated zone in naturally fractured reservoirs, especially CBM. However, big discrepancies between the modelling results of graded proppant injection and the experimental results have been observed. An analytical model of graded proppant injection with consideration of proppant embedment and deformation is established in this paper, and the influences of proppant embedment and deformation are investigated.
An analytical model of calculating the permeability of a fracture filled with partial monolayer proppant is established, and a linear elastic model of calculating proppant embedment and deformation is coupled into it to investigate the influences of proppant embedment and deformation on propped fracture permeability. The influences of proppant embedment and deformation on propped fracture permeability and the optimal proppant packing ratio are investigated. The influences of properties of proppant and rock on propped fracture permeability and the optimal proppant packing ratio are also studied. The graded proppant injection schedules with and without consideration of proppant embedment and deformation are compared and practical understandings are obtained.
The results show that the propped fracture permeability is reduced by more than 50% when the embedment or deformation extent reaches 18%. Neglecting proppant embedment and deformation will lead to an under-estimation of 15%-18% for the optimal proppant concentration during graded proppant injection. Proppant diameter has little influence on the optimal proppant packing ratio. Lower Elastic Modulus in the proppant or rock and/or smaller proppant particles leads to a higher optimal proppant packing ratio and lower permeability correction factors. Poisson's ratio of proppant or rock has very little influence on both optimal proppant packing ratio and permeability correction factor. Proppant concentrations at different stages of graded proppant injection with consideration of proppant embedment and deformation are 21.8% higher than those neglecting the two factors. Proppant embedment and deformation must be considered during planning of the graded proppant injection schedule.
Sato, Ken (Waseda University) | Shinohara, Kenji (Waseda University) | Furui, Kenji (Waseda University) | Mandai, Shusaku (Mitsubishi Chemical Corporation) | Ishihara, Chizuko (Mitsubishi Chemical Corporation) | Hirano, Yasuhiro (Mitsubishi Chemical Corporation) | Taniguchi, Ryosuke (Mitsubishi Chemical Corporation, Now with Soarus L.L.C.)
It has been reported that hydraulic fracturing treatments with smaller cluster spacing and larger fracturing fluids volumes yield better production performance in Permian Basin, Bakken, and Eagle Ford. Degradable diverting agents can play an important role as temporary plugging materials for multiple, tightly-spaced fracturing operations. However, applications of degradable diverting agents are often limited to moderate to high reservoir temperatures. In this study, a new degradable diverting agent is developed for use in low temperature reservoir applications.
Butane-diol vinyl alcohol co-polymer (BVOH) which has controllable water solubility is evaluated as diverting agents for hydraulic fracturing treatments. Using a high pressure-high temperature filtration apparatus, filtration properties of BVOH diverting agents are measured for various powder-to-pellet ratios under a range of temperature conditions. Filter media with 1 to 3 mm width slots, that simulate fracture openings, are used for the filtration test. The filtrate properties are evaluated based on spurt losses and filtration coefficients for quantitative evaluation. An analytical diverting agent model that considers swelling of the polymer in water is also developed for evaluating the filtration process of multimodal particles.
The experimental results presented in this work indicate that the degradable BVOH materials can be used as effective plugging agents for fracture-like narrow slits. Based on spurt losses and leakoff coefficients obtained under different powder-to-pellet ratios and temperature conditions, the performance of the diverting agents is quantitatively evaluated. The optimum powder-to-pellet ratio for BVOH materials are determined to be 80 to 20. The experimental results also reveal that the degree of BVOH crystallinity provides a dominant effect on the solubility of BVOH powder. The test results also indicate that the diverting agent plug properties started degrading under the temperature greater than 140°F as designed. The BVOH diverting agent developed in this work provides effective diversion effects under low to moderate temperature conditions (e.g., 80 to 100°F). The analytical plugging and bridging model developed in this work, which takes into account swelling properties of the polymer, show very good matches to the experimental results.
The degradable diverting agent developed for low temperature applications improve operational efficiency and economics of multistage hydraulic fracturing treatments in shallow reservoirs and operations where immediate fracturing fluid flowback is required. The plugging and bridging model with bimodal particle system developed in this study helps stimulation engineers select and optimize diverting agent material types, particle size distribution, and diverting agent concentration for various well, stimulation, and reservoir conditions.
Neutral wet proppant plays a pivotal role in maximizing the flow back of fracturing fluids and the recovery of produced hydrocarbons. An accurate and repeatable contact angle measurements are extremely challenging because of proppant spherical shape and small size. This paper presents a methodology of direct contact angle measurements in spherical particles examined with high strength coated ceramic proppant.
20/40 and 25 HSP non coated proppants were used for the study. Coating material was applied to the proppant sample to obtain non-wetting characteristics. KRUSS Drop shape Analyzer was utilized to measure the contact angle using a modified pendent drop method. Step by step procedure is detailed and possible sources of errors were identified, and recommendations were introduced accordingly.
HSP coated proppant showed contact angle measurements of 117-120° and 84-114° with deionized water and hydrocarbon samples, respectively. Ideally, a neutrally wetted surface would have a contact angle of 90°. This indicates that the proppant is neutral to slightly oil-wet. Wetting characteristics are dependent of hydrocarbon type. For instance, Condensate 2 have a contact angle of 102.3° indicating neutral wetting characteristics, whereas Condensate 3 shows contact angle of 84.5° indicating slightly oil-wet character. Geometry of hydrocarbon droplets modified the adhesion tension of oil, nevertheless had insignificant effect with water drops. For example, tripling the droplet size of Condensate 2 and Diesel resulted in increment in contact angle values of 12° and 15°, respectively.
Li, Lei (Key Laboratory of Unconventional Oil & Gas Development, School of Petroleum Engineering, China University of Petroleum, East China) | Su, Yuliang (Key Laboratory of Unconventional Oil & Gas Development, School of Petroleum Engineering, China University of Petroleum, East China) | Chen, Zheng (Key Laboratory of Unconventional Oil & Gas Development, School of Petroleum Engineering, China University of Petroleum, East China) | Fan, Liyao (Key Laboratory of Unconventional Oil & Gas Development, School of Petroleum Engineering, China University of Petroleum, East China) | Tang, Meirong (Research Institute of Oil and Gas Technology, PetroChina Changqing Oilfield Company) | Tu, Jiawei (School of Petroleum Engineering, Texas Tech University)
Fracturing is the necessary means of tight oil development and the most common fracturing fluid is slickwater. However, the loess plateau of ordos basin in China is seriously short of water resources. Therefore, the tight oil development in this area by hydraulic fracturing is extremely expensive and bad for the environment. In this paper, a new method using CO2 as pre-fracturing fluid is applied in hydraulic fracturing. This method can give full play to the dual advantages of supercritical CO2 characteristics and mixed water fracturing technology while saving water resources at the same time. On the other hand, this method can reduce reservoir damage, change rock microstructure, and significantly increase oil production after full interaction with formation fluid, which is a development method with broad application prospect.
In this work, the main mechanism, the the system energy enhancement, and flowback rate of CO2 as pre-fracturing fluid are investigated. Firstly, the microscopic mechanism of CO2 fracturing was studied, and the effects of CO2 on pores and rock minerals were analyzed by NMR test, XRD analysis and SEM experiment. Secondly, the high pressure chamber reaction experiment was conducted to study the distribution and existence state of supercritical CO2 in the multiphase fluid during the full-cycle fracturing process. Finally, four injection modes of CO2 injection experiments were designed to compare the pressure increase, production enhancement, and flowback rate of CO2 and slickwater, so as to optimize the optimal CO2 injection mode and the optimal injection amount of CO2 slug.
The results show that supercritical CO2 can increase the porosity of rocks by dissolving calcite and clay minerals (illite and chlorite) that gather around the pores according to the changes of pore size and rock composition before and after CO2 action. Supercritical CO2 injection increases the saturation pressure, expansion coefficient, volume coefficient, density, and compressibility of crude oil, which are the main mechanisms of fracturing energy increase and production enhancement. After analyzing the four different injection modes tests, the optimal one is to first inject CO2 and then inject slickwater for fracturing. The CO2 slug has the optimal value which is 0.5 pore volume in this study.
In this study, supercritical CO2 is used as the pre-fracturing fluid, providing a new idea for the stimulation of tight oil. Experimental studies have proved the pressure increase, production enhancement, and flowback potential of CO2 pre-fracturing. The application of this method is of great significance to the protection of water resources and the improvement of fracturing effect.
Ahmed, Shehzad (Khalifa University of Science and Technology) | Alameri, Waleed (Khalifa University of Science and Technology) | Ahmed, Waqas (King Abdullah University of Science and Technology) | Khan, Sameer (King Abdullah University of Science and Technology)
CO2 foam as a fracturing fluid for unconventional reservoir has been of huge interest due to its potential in solving various challenges related to conventional water-based fracturing. The rheological property of CO2 foam is a key factor controlling the efficiency of fracturing process and it is strongly influenced by different parameters such as foam quality, temperature, pressure and shear rate. The quantification of these parameters under reservoir conditions leads to the design of optimum injection strategy. However, the traditional modeling approaches are unable to provide fast and accurate prediction while considering combined effect of all these parameters. Here, we proposed a data driven approach based on supervised deep learning to estimate rheological property of CO2 foam as a function of foam quality, temperature, pressure, and shear rate. We exploit deep neural networks (DNNs) that are trained to learn the complex nonlinear aspects of the data. For the data generation, we performed a series of experiments for CO2 foams by varying different process variables. CO2 foams at different qualities were generated using conventional surfactant in a flow loop system and foam viscosity measurements were performed at HPHT under wide range of shear rate. The architecture of DNN was optimized to accurately estimate the foam apparent viscosity for given foam quality, temperature, pressure, and shear rate. The predictive capability of designed network is found to be significantly high, analyzed by regression coefficient approaching unity, low mean squared error, and low average absolute relative deviation (≪ 2.5%). The designed neural network allows robust and accurate prediction of foam apparent viscosity at different foam qualities under various reservoir condition, which demonstrates its practicality for CO2 foam projects for fracturing unconventional reservoirs.
Chaplygin, Dmitry (Company Salym Petroleum) | Azamatov, Marat (Company Salym Petroleum) | Khamadaliev, Damir (Company Salym Petroleum) | Yashnev, Viktor (Company Salym Petroleum) | Novikov, Igor (Geosplit LLC) | Drobot, Albina (Geosplit LLC) | Buyanov, Anton (Geosplit LLC) | Ovchinnikov, Kirill (Geosplit LLC) | Husein, Nadir (Geosplit LLC)
The paper describes the use of new generation of inflow chemical tracer application at Salym Petroleum Development Upper-Salym oilfield as a part of Smart Field project. This kind of well surveying using indicators that allow the evaluation of the inflow composition for each hydraulic fracturing port in horizontal wells remotely, without any additional risky and costly downhole activities.
The new inflow chemical tracer technology is based on the use of nano-particle quantum dots, which give a level of high accuracy in quantitative analysis of fluid inflow. Markers, which are micromillimeter in size, are inserted into the polymer coating of the proppant. The technology involves the injection of marked polymer-coated proppant in the process of MHF (multi-stage hydraulic fracturing). Once the MHF is done, and the well is producing, the fluid samples are taken at surface and tested in a laboratory using machine learning software. Once the obtained data is interpreted, a flow profile of oil and water can be generated for each frac stage.
One of the main advantages of marker technologies is that they provide data over a long period of time, with a significant reduction in operating cost. It opens the door for new opportunities in terms of more accurate reservoir characterization and better hydrocarbon recovery. The key element of the technology is the use of specialized intelligent machine-learning software based on Random Forest algorithm to produce production flow profile.
The described methodology was used during the multi-stage hydraulic fracturing operation on oil wells 8105 and 8064 of Upper-Salym field. The volume of proppant injection at each stage was 20 tons, out of which 15 tons were of marked proppant containing a unique code for each stage. As soon as marked proppant has a contact with well fluid markers are emitted into fluid and sampling at the wellhead can be done any time when information required. The results of samples analysis are reports with graph showing quantitative distribution of water and oil production of each fracturing interval.
The new generation of inflow markers allows for continuous production, surveillance and quantitative analysis of oil and water phase from each fracturing stage. This enables better decision making to optimize the production and make better decisions for water conformance interventions. This surveillance method does not require complex and risky well interventions or production shutdowns, making it substantially more cost effective than the existing conventional methods.
Optimization of oil production, remote monitoring for risks minimization, reduction of operating costs - all these are the results of the introduction of Smart Fields technology systems in the Salym group of oilfields.
Proppant flowback from hydraulic fracturing is widespread and costly due to erosion and/or blockage of producing hydrocarbons due to proppant accumulation. One remedy is to install sand control equipment integrated into a sliding sleeve device (SSD) as part of the completion string, which raises concern about erosion during fracturing. While some installations have been successful, at least one experienced sand control failure. Computational Fluid Dynamics (CFD) was deployed to evaluate the root cause and identify more robust designs, as presented herein.
Firstly, we identified the most probable causes of sand control failure during multistage fracturing (MSF) in openhole (OH) horizontals. State-of-the-art CFD simulations were then performed on the installed design using actual flow conditions (rates, slurry properties, treatment time) from a failed installation. The static CFD methodology in an initial undeformed geometry proved to be ultra-conservative, so a new quasi dynamic mesh (QDM) methodology was developed, which yielded more realistic (albeit still conservative) erosion-depth predictions. The results revealed areas for improving the design of key components, and CFD was re-run to confirm erosion resistance targets. The modifications were then implemented for a field trial.
Since frack location between two openhole packers is unknown, and the frack port is located between multiple screen/SSD assemblies, one must consider annular flow across the assembly in both directions. Accurate CFD predictions of erosion of completion components versus time during MSF in OH proved challenging. The quicker static methods were useful in ruling out some components as problem areas, such as the sand control media, but proved overly conservative on other key components. The QDM methodology gave more realistic results and indicated that erosion depths in specific locations could be deep enough to possibly cause sand control failure. To reduce the erosion risk, such components were modified, and the result was a reduction in predicted erosion depths to acceptable levels. A safety factor was already built into the predictions because of two key conservative assumptions: ignored initially were 1) particle-particle interaction and 2) erosion of the reservoir wall. The former was further investigated.
While waiting for the field trial results, the main conclusion thus far is that CFD is a valuable tool for diagnosing erosion failures and improving equipment design. However, it’s essential to use a methodology that realistically captures downhole conditions. Presented herein is a more robust design of a screen/SSD assembly for proppant flowback control, as well as an improved CFD methodology for diagnosing sand control failures during MSF and for identifying design improvements of completion equipment. Furthermore, the inherent challenges of controlling proppant flowback without causing erosion or flow blockage of hydrocarbons are discussed.
Yudin, Alexey (Schlumberger) | ElSebaee, Mohamed (Schlumberger) | Stashevskiy, Vladimir (Schlumberger) | Al Baik, Abdullah (Schlumberger) | AlJanahi, Ahmed (Tatweer Petroleum) | Abdelrady, Sayed (Tatweer Petroleum) | Darwish, Saeed (Tatweer Petroleum) | Al Askari, Nasser (Tatweer Petroleum)
The Ostracod formation in the Awali brownfield is an extremely challenging layer to develop because the tight carbonate rock is interbedded with shaly streaks and the presence of a nearby water-bearing zone. Although the Ostracod formation has been in development since 1960, oil recovery has not yet reached 5% because past stimulation attempts experienced rapid production decline. The current project incorporated aggressive fracture design coupled with a unique height growth control (HGC) workflow, improving the development of Ostracod reserves.
The HGC technology is a combination of an engineering workflow supported by geomechanical modeling and an advanced simulator of in-situ kinetics and materials transport to model the placement of a customized, impermeable mixture of particles that will restrict fracture growth. The optimized treatment design included injections of the HGC mixture prior to the main fracturing treatment. This injection was done with a nonviscous fluid to improve settling to create an artificial barrier. High-resolution temperature logging was used before the main treatment to calibrate and optimize the pumping schedule, and fracture geometry was measured independently with an acoustic scanning tool after the stimulation.
The high clay content within the Ostracod layers creates a significant challenge for successful stimulation. The high clay content prevents successful acid fracturing and leads to severe embedment with conventional proppant fracturing designs. We introduced a new approach to stimulate this formation with an aggressive tip-screenout design incorporating a large volume of 12/20-mesh proppant to obtain greater fracture width and conductivity, resulting in a significant and sustained oil production gain. The carefully designed HGC technique was efficient in avoiding fracture breakthrough into the nearby water zone, enabling treatments of up to 450,000 lbm to be successfully contained above a 20-ft-thick shaly barrier with small horizontal stress contrast. Independent measurements proved that the fracture height was successfully contained. Wells treated with this optimized workflow produced up to 22,000 bbl of oil within first 8 months with negligible water cut, which significantly exceeded all previous stimulation results in the field. This trial campaign in vertical wells proved that the combination of aggressive, large fracture designs with the HGC method could help unlock the Ostracod's potential.
The applied height growth control technique was modified with additional injections and improved by advanced modeling that only recently became available. These contributed to a significant increase of treatment volume, making the jobs placed in the Ostracod some of the world's largest utilizing HGC techniques. The experience gained in this project can be of a paramount value to any project dealing with hydraulic fracturing near water formation with insufficient or uncertain stress barriers.