The artificial lift system (AL) is the most efficient production technique in optimizing production from unconventional horizontal oil and gas wells. Nonetheless, due to declining reservoir pressure during the production life of a well, artificial lifting of oil and gas remains a critical issue. Notwithstanding the attempt by several studies in the past few decades to understand and develop cutting-edge technologies to optimize the application of artificial lift in tight formations, there remains differing assessments of the best approach, AL type, optimum time and conditions to install artificial lift during the life of a well. This report presents a comprehensive review of artificial lift systems application with specific focus on tight oil and gas formations across the world. The review focuses on thirty-three (33) successful and unsuccessful fieldtests in unconventional horizontal wells over the past few decades. The purpose is to apprise the industry and academic researchers on the various AL optimization approaches that have been used and suggest AL optimization areas where new technologies can be developed.
Out-Of-Sequence (OOS) Fracturing can potentially maximize reservoir contact and fracture conductivity/connectivity by creating fracture complexity via reducing the stress anisotropy. It is initiated by fracturing two "book-end" frac stages (Outside Fracs), followed by a ‘middle" stage (Centre Frac) between them. The Center Frac is theorized to utilize the reduced stress anisotropy to activate pre-existing failure surfaces oriented at various azimuths and dip angles, thereby connecting bi-wing fractures to planes of weakness (natural fractures/fissures/faults/joints/cleats) and resulting in a complex fracture network that enhances connectivity and fracture area within the Stimulated Reservoir Volume (SRV). OOS Fracturing can mitigate possible issues in treatments aiming at creating fracture complexity, including zipper frac (fracture tip interference and blunting inhibiting fracture extension), modified zipper frac (risks of well bashing and fractures growing asymmetrically opposite of the induced stress from prior stage in the adjacent well), simultaneous frac (middle clusters experiencing larger stress interference inhibiting their growth), and high-rate fracturing (risk of cluster erosion reducing the limited entry effect and premature screenout due to inconsistent diversions inside fractures).
Since its inception in early 2010s, OOS Fracturing has not gained considerable attention due to previously-existing operational limitations in fracturing out-of-sequence. It is reported to have been field tested in Western Siberia in 2014 with claimed well performance success. Operational limitations of the system employed in that trial is believed to have prevented its commercial development at that time. With the advent of Multicycle Sleeves and Shift-Frac-Close operation with a single Bottom-Hole Assembly to open and close sleeves, previous operational limitations of OOS Fracturing have been resolved. OOS Fracturing has since been trialed in three formations in Western Canada (2017/2018). This work analyzes the fracture treatment pressures and well performance of these trials.
Five OOS Fracturing trials in these three formations reveal that normalized 15-month/18-month production from out-of-sequence-fractured wells outperform that of sequentially-fractured offsets, with similar formation properties and treatment designs. Instantaneous Shut-In Pressures (ISIP) of Centre Frac are generally higher than that of either Outside Fracs. Breakdown pressures for Centre Fracs exhibit a mixed trend, confirming that reducing stress anisotropy could lower the breakdown gradient (based on Kirsch Equation) if rock fabric permits. Well performance and treatment pressures appear to be more sensitive to Centre Frac proppant tonnage/fluid volumes and uneven sleeve spacing.
This is the first attempt in analyzing the five OOS Fracturing trials, with encouraging well performance and operational execution in conventional reservoirs where it was deployed. Despite uneven sleeve spacing, depletion due to offset production, and less favorable geomechanical properties (high Poisson’s Ratio and low Young’s Modulus), field trials produced favorable results. True potential of non-sequential fracturing is potentially more promising in unconventional reservoirs with formation properties more conducive to complex fracture generation.
Quintero, Harvey (ChemTerra Innovation) | Abedini, Ali (Interface Fluidics Limited) | Mattucci, Mike (ChemTerra Innovation) | O’Neil, Bill (ChemTerra Innovation) | Wust, Raphael (AGAT Laboratories) | Hawkes, Robert (Trican Well Service LTD) | De Hass, Thomas (Interface Fluidics Limited) | Toor, Am (Interface Fluidics Limited)
For optimizing and enhancing hydrocarbon recovery from unconventional plays, the technological race is currently focused on development and production of state-of-the-art surfactants that reduce interfacial tension to mitigate obstructive capillary forces and thus increase the relative permeability to hydrocarbon (
A heterogeneous dual-porosity dual-permeability microfluidic chip was designed and developed with pore geometries representing shale formations. This micro-chip simulated Wolfcamp shale with two distinct regions: (i) a high-permeability fracture zone (20 µm pore size) interconnected to (ii) a low-permeability nano-network zone (100 nm size). The fluorescent microscopy technique was applied to visualize and quantify the performance of different flowback enhancers during injection and flowback processes.
This study highlights results from the nanofluidic analysis performed on Wolfcamp Formation rock specimens using a microreservoir-on-a-chip, which showed the benefits of the multi-functionalized surfactant (MFS) in terms of enhancing oil/condensate production. Test results obtained at a simulated reservoir temperature of 113°F (45°C) and a testing pressure of 2,176 psi (15 MPa) showed a significant improvement in relative permeability to hydrocarbon (
Measurements using a high-resolution spinning drop tensiometer showed a 40-fold reduction in interfacial tension when the stimulation fluid containing MFS was tested against Wolfcamp crude at 113°F (45°C). Also, MFS outperformed other premium surfactants in Amott spontaneous imbibition analysis when tested with Wolfcamp core samples.
This work used a nanofluidic model that appropriately reflected the inherent nanoconfinement of shale/tight formation to resolve the flowback process in hydraulic fracturing, and it is the first of its kind to visualize the mechanism behind this process at nanoscale. This platform also demonstrated a cost-effective alternative to coreflood testing for evaluating the effect of chemical additives on the flowback process. Conventional lab and field data were correlated with the nanofluidic analysis.
Today, almost half of Western Canada's natural-gas production comes from the Triassic-aged Montney formation, a sixfold increase over the last 10 years while gas production from most other plays has declined. In the last few years, demand for condensate as diluent for shipping bitumen has driven development of liquids-rich Montney natural gas leading to a surge in gas production and gas-on-gas competition in the Western Canadian Sedimentary Basin (WCSB), which has driven local natural gas prices down. This has had a material effect on the operations and finances of companies active in the Western Canada and is reshaping the Canadian gas industry. A significant portion of this growth has taken place in NE British Columbia and with the planned electrification of the industry in British Columbia, including the nascent LNG operations, will influence tomorrow's power industry in this region. NE British Columbia is a geographically large area with sparse population and the power supply into this region has lagged behind development of oil and natural gas resources. The area was originally served from geographically closer NW Alberta. More recently, supply was established from the BC Hydro power grid with the most significant developments being Dawson Creek-Chetwynd Area Transmission (DCAT) completed in 2016 and the additional 230 kV transmission projects scheduled for completion in 2021.
Zaluski, Wade (Schlumberger Canada LTD) | Andjelkovic, Dragan (Schlumberger Canada LTD) | Xu, Cindy (Schlumberger Canada LTD) | Rivero, Jose A. (Schlumberger Canada LTD) | Faskhoodi, Majid (Schlumberger Canada LTD) | Ali Lahmar, Hakima (Schlumberger Canada LTD) | Mukisa, Herman (Schlumberger Canada LTD) | Kadir, Hanatu (Schlumberger Canada Limited now with ExxonMobil) | Ibelegbu, Charles (Schlumberger Canada Limited) | Pearson, Warren (Pulse Oil Operating Corp) | Ameuri, Raouf (Schlumberger Canada Limited) | Sawchuk, William (Pulse Oil Operating Corp)
Enhanced oil recovery (EOR) is an economic way of producing the remaining oil out of previously produced Devonian Pinnacle Reefs in the Nisku Formation within the Bigoray area of Alberta. To maximize the recovery factor of the remaining oil, it was necessary to first characterize the geological structure, matrix reservoir properties, vugular porosity and the natural fracture network of these two carbonate reefs. This characterization model was then used for reservoir simulation history matching and production forecasting further discussed by (
Oil production from shale and tight formations will increase to more than 6 million barrels per day (b/d) in the coming decade, making up most of total U.S. oil production (> 50%). However, achieving an accurate formation evaluation of shale faces many complex challenges. One of the complexities is the accurate estimation of shale properties from well logs, which is initially designed for conventional reservoirs. When we use the well logs to obtain shale properties, they often cause some deviations. Therefore, in this work, we combine cores and well logs together to provide a more accurate guideline for estimation of total organic carbon, which is primarily of interest to petroleum geochemists and geologists.
Our work is based on Archie's equation. Resistivity log will lead to some incorrect results, such as total resistivity, when we follow the conventional interpretation procedure in well logs. Porosity is another complex parameter, which cannot be determined only by well log, i.e. density, NMR, and Neutron log. Therefore, the flowchart of TOC calculation includes five main parts: (I) the shale content calculation using Gamma log; (II) the determination of shale distributions using Density and Neutron logs and cross-plot; (III) the calculation of total resistivity at different distribution types; (IV) obtaining porosity using core analysis, NMR and density logs; and (V) the calculation of TOC from modified Archie's equation.
The results indicate that the shale content has a strong effect on estimation of water saturation and hydrocarbon saturation. Especially, the effect of shale content is exacerbated at a low water saturation. A more accurate flowchart for TOC calculation is established. Based on Archie's equation, we modify total resistivity and porosity by combining Gamma Log, Density Log, Neutron Log, NMR Log, and Cross-plot. An easier way to estimate porosity is provided. We combine the matrix density and kerogen density together and obtain them from core analysis. Poupon's et al. (1954) laminar model has some limitations when applying in shale reservoirs, especially at a low porosity.
Literature surveys show few studies on the flowchart of TOC calculation in shale reservoirs. This paper provides some insights into challenges of well logs, core analysis in shale reservoirs and a more accurate guideline of TOC calculation in shale reservoirs.
The goal of this work is to evaluate the applicability of a novel set of surfactants to enhance recovery from a viscous oil, high temperature, high permeability, clastic reservoir. A large number of novel short-hydrophobe based surfactants/cosolvents were designed and synthesized. As these surfactants do not require expensive aliphatic alcohols for their synthesis, they are likely to be less costly than conventional anionic surfactants. Here only phenol hydrophobe based non-ionic surfactants with varying number of propylene oxide (PO) and ethylene oxide (EO) groups are discussed. These surfactant molecules were investigated for their aqueous stability limits, interfacial tensions (IFT) with a viscous crude oil and oil recovery from sandpack or sandstone cores. Surfactant phase behavior experiments with viscous crude oil showed low IFT (not ultralow) for single surfactant systems. Only one surfactant (Phenol-7PO-15EO) formulation was chosen for coreflood in sandpack and sandstone cores. Water flood recovered about 50% original oil in place (OOIP) and reduced the oil saturation to about 48% in the high permeability sandpacks. The tertiary surfactant polymer flood with Phenol-7PO-15EO increased the cumulative recovery to 99% for sandpacks. The oil recovery was insensitive to injection brine salinity in the range studied. As the permeability decreased, the tertiary oil recovery decreased if the permeability is lower than 7 Darcy. Surfactant-polymer (SP) formulations with this surfactant can be recommended for high permeability sandstone reservoirs with viscous oils, but not for sub-Darcy sandstones.
Quintero, Harvey (ChemTerra Innovation) | Farion, Grant (Trican Well Service LTD.) | Gardener, David (ChemTerra Innovation) | O'Neil, Bill (ChemTerra Innovation) | Hawkes, Robert (Trican Well Service LTD.) | Wang, Chuan (ChemTerra Innovation) | Cisternas, Pablo (American Air Liquide) | Pruvot, Antoine (American Air Liquide) | McAndrew, James (American Air Liquide) | Tsuber, Leo (Badger Mining Corporation)
This study aims to demonstrate the true benefit of an innovative salt tolerant high viscosity friction reducer (HVFR) that excels at promoting extended proppant suspension and vertical distribution into the fracture when it is used as a base fluid for the Capillary Bridge Slurry (CBS) and other conventional fracturing fluid systems in combination with nitrogen.
The completion of super-lateral wells now being drilled in tight oil and gas shales in North America, with record lengths close to 4 miles, demand for greater carrying capability of low viscosity (slickwater) fracturing fluids, where significant sand settling can occur before the proppant even reaches the fractures. This has sparked recent interest in the development and application of salt tolerant polyacrylamide-based friction reducers, referred to as High Viscous Friction Reducers (HVFR). The downfall of these first generation HVFR's is the lack of compatibility with high salinity brines such as recycled and flowback water, and diminished ability to reduce friction pressure during hydraulic fracturing treatments when compared to industry standard FR's.
Herein, we report the field application of a unique salt tolerant HVFR (HVFR-ST), that consistently provides higher viscosity values (corresponding industry standard HVFR loading comparison) when tested in brines, without sacrificing friction reduction effectiveness. Additionally, a new concept of fracturing fluid referred to as Capillary Bridge Slurry (CBS) has been successfully implemented in North America, where through a surface modification to the proppant, the addition of a gas phase such as N2, and the use of a polyacrylamide-based friction reducer, the proppant becomes part of the fluid structure and is no longer the burden to be carried. The combination of HVFR's and the surface modified proppant can effectively combat the issues faced with proppant transport in long laterals.
This paper will highlight the results on the analysis of the governing proppant transport mechanisms (suspended and bed) of CBS system formulated with HVFR-ST, in the presence of nitrogen (N2), where no detrimental effect in the average distance traveled of the sand particle in the Proppant Transport Test Bench (PTTB) was observed when the brine concentration of the base fluid was increased from 1% to 5% in comparison to industry standard HVFR (HVFR-FW).
Field production data on wells stimulated with CBS show a significant upside (~ 50%) in liquid hydrocarbon production than offsetting wells over a ~ one year period of time.
Friction loop data carried out at 45 L/min (11.89 gals/min) flow rate in an internal diameter pipe of 0.305" shows a reduction on friction pressure in excess of 70%, when HVFR was tested in 5% API brine (4% (w/v) NaCl and 1% (w/v) CaCl2·2H2O) at loadings as low as 0.1%. Furthermore, dynamic measurements within the viscoelastic regime/behavior of the HVFR at different loadings in the oscillatory viscometer will provide learnings on the elasticity-proppant transport relationship of the different fracturing fluid systems.
Through the use of laboratory testing and field study cases, this paper will illustrate the true benefits on the use of salt tolerant HVFR's as a base fluid with the increasing demand of re-cycled and flowback water use in fracturing fluid systems.
Rivero, Jose A. (Schlumberger Canada Limited) | Faskhoodi, Majid M. (Schlumberger Canada Limited) | Mukisa, Herman (Schlumberger Canada Limited) | Zaluski, Wade (Schlumberger Canada Limited) | Ali Lahmar, Hakima (Schlumberger Canada Limited) | Andjelkovic, Dragan (Schlumberger Canada Limited) | Xu, Cindy (Schlumberger Canada Limited) | Ibelegbu, Charles (Schlumberger Canada Limited) | Kadir, Hanatu (Schlumberger Canada Limited) | Sawchuk, William M. (Pulse Oil) | Pearson, Warren (Pulse Oil) | Ameuri, Raouf (Schlumberger Canada Limited) | Gurpinar, Omer (Schlumberger)
The Bigoray area of the Pembina field in western Alberta consists of approximately 50 naturally-fractured Nisku carbonate reefs. Production from the Bigoray Nisku D and E Pools started in 1978, and shortly after, water injection was initiated to maintain reservoir pressure as a secondary drive mechanism. By 2013, the pools had reached high water-cuts, making them uneconomical to produce. In 2017, a decision was made to reactivate the pools and initiate a solvent injection Enhanced Oil Recovery (EOR) project feasibility assessment.
A multi-disciplinary team was assembled to review and reinterpret all the geoscience data with modern methodologies to characterize the reservoirs and create new static model descriptions to be used in a dynamic model. Data from well logs, seismic, core measurements and image logs was integrated into a comprehensive and consistent model that could be used with certainty as a prediction tool.
A history-matching process was carried out by creating different realizations of the static model to honor well-to-well connectivity and water movement within the pools. The history-matching process was performed while ensuring that the model updates were global in nature and consistent with the geological understanding of the reservoirs.
The history-matched model was used to optimize the location of new producers and injectors based on remaining oil saturations and reservoir structure. Optimization of the EOR scheme involved testing a matrix of scenarios to investigate the effect of injection rates, solvent volumes as well as production pressures and voidage ratios. Additionally, in an effort to improve displacement efficiency, a large number of simulation runs were devoted to test and establish the most efficient locations for the well perforations in both the new injectors and producers.
Abdelfatah, Elsayed (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada) | Wahid-Pedro, Farihah (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada) | Melnic, Alexander (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada) | Vandenberg, Celine (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada) | Luscombe, Aidan (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada) | Berton, Paula (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada) | Bryant, Steven (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada)
Waterflooding of heavy oil reservoirs is commonly used to enhance their productivity. However, preferential pathways are quickly developed in the reservoir due to the significant difference in viscosity between water and heavy oil, and hence, the oil is trapped. Here, we propose a platform for designing ultra-low IFT solutions for reducing the capillary pressure and mobilizing the heavy oil.
In this study, mixtures of organic acids and bases were formulated. Three different formulations were tested: (i) Ionic liquid (IL) formulation where bulk acid (4-dodecylbenzene sulfonic acid) and base (Tetra-
The IL and ABs formulation are acidic solutions with pH around 3. The ASBs formulation is highly basic with a pH around 12. Non of the formulations salted out below 14 wt% of NaCl. While conventional surfactant, SDBS, precipitated at salt concnetration less than 2 wt% of NaCl. The formulation solutions (1 wt%) have different optimum salinities: 2.5 wt% NaCl for ASBs, 3 wt% NaCl for IL and AB. Although IL and AB have the same composition and molar ratio of the components, their performances are completely different, indicating different intermolecular interactions in both formulations. Corefloods were conducted using sandpack saturated with Luseland heavy oil (~15000 cP) and at fixed Darcy velocity of 12 ft/day. A slug of 1 PV of each formulation was injected after waterflooding for 5 PV and followed by 5 PV post-waterflooding. In the hydrophilic sandpacks, IL and AB formulation produced an oil bank, consisting mainly of W/O emulsion, with oil recovery that is 1.7 times what was recovered by 11 PV of waterflooding solely. Majority of the oil was recovered in the 2 PV of waterflood following the IL slug. ASBs formulations produced O/W emulsions with prolonged recovery over 5 PV waterflooding after the ASB slug. The recovery factor for ASBs was 1.6 times that recovered for 11 PV of waterflooding only. In the hydrophobic sandpacks, The ASB formulation slightly increased the recovery factor compared to only waterflooding. While for IL and AB formulation, the recovery factor decreased.
This work presented a novel platform for tuning the recovery factor and the timescale of recovery of heavy oil with a variable emulsion type from O/W to W/O depending on the intermolecular interactions in the system. The results demonstrate that the designed low IFT solutions can effectively reduce the capillary force and are attractive for field application.