This paper presents a method for pinpointing intervals for fracture stimulation in horizontal wells targeting unconventional oil plays. The observation of crossflow among fractures has been of great concern as this phenomenon affects the productivity of producing wells. The cause is related to the effectiveness of fracturing stages, which by itself depends on the rock lithology. We identified interaction among fractured intervals from diagnostic modeling of performance data that exhibited cross flows in the wellbore. On wells exhibiting the most prolonged duration of crossflow, we noted the disadvantages of equal space fracturing. We then used the drilling parameters from MWD data for individual wells and computed the d-exponent profiles and noted significant differences in rock brittleness as characterized by their d-exponent data. Out of the more than 60 wells studied, wells exhibiting minor changes in the d-exponent showed the least indications of cross flows from performance data while in wells with significant cross flows we see the nonuniformity of the d-exponent profile and the negative impact of equal space fracturing.
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.
Eldabbour, Mohamed (Abu Qir Petroleum) | Fadel, Ayman (Abu Qir Petroleum) | Soliman, Ali (Abu Qir Petroleum) | Safwat, Hatem (Abu Qir Petroleum) | Labib, Amr (Abu Qir Petroleum) | Belli, Andrea (Abu Qir Petroleum) | McLaughlin, Ryan (Corex U.K. Ltd) | Patey, Ian T.M. (Corex U.K. Ltd) | Munro, Murdo S. (Corex U.K. Ltd) | Jones, David (Corex U.K. Ltd)
Gravel pack completion operations are a sand production management technique that is considered successful if the well produces no sand and has minimal impact upon the potential productivity and hydrocarbon recovery. However, statistics show that many gravel packed wells suffer reduced productivity as a result of damaging mechanisms induced by gravel pack operations and completion fluids. This provides an opportunity for improved hydrocarbon recovery if the mechanisms are understood.
A study was conducted to simulate the alterations caused by the gravel pack operations including gravel carrier fluid, completion fluid and lost circulation material. Simulations using reservoir core samples were carried out at near-wellbore conditions, in order to examine operational fluid interactions with the reservoir and assess the impact of a stimulation fluid. Cores from a range of rock types were selected, and prepared to initial gas-leg saturation. An operational sequence consisting of completion fluid, gas production, stimulation fluid, completion fluid, and production of gas was carried out, with permeability measurements before and after the sequence.
In all core samples, the introduction of the completion fluid during gravel pack installation resulted in alterations of 30-60% reduction in core permeability. Geological interpretative analysis showed damage mechanisms including clay fines movement and pore blockage, dissolution of native cement, and retention of operational fluid in the pores. It was believed that retention of fluids was having the most significant impact upon permeability. Stimulations were carried out for all samples to quantify the effect of acid on removing the formation damage resulting from the gravel pack operations. The experiments showed 5-10% improvement on average except for one core sample, which showed 40% improvement.
Based upon the previous results, a modified sequence was examined, utilizing an alternative stimulation fluid/acid sequence and adding an extra operational stage. The experiments showed that after treatment an improvement of around 10% was noted, and after an additional stage, a further 8% improvement was seen. The final permeability was over 80-90% of the initial permeability, indicating that there was the potential for good productivity and recovery of hydrocarbons.
The results of the study were applied to seven gravel pack jobs in three wells and the field results showed the reduction in productivity after gravel pack installation was around only 10%, compared to previous wells which showed more than 50% reduction in productivity.
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.
Bruce Stuart has been named as vice president of sales and business development for Europe and West Africa for Proserv. Stuart was previously the sales and marketing manager for the United Kingdom and Canada at FMC Technologies, and has worked in senior sales roles at Cameron and Dril-Quip during his 30 years in the industry.
Khedr, Sherine (BP Exploration Operating Co) | El-dabi, Fady (BP Exploration Operating Co) | Nashaat, Mohamed (BP Exploration Operating Co) | Mohiuldin, Ghulam (BP Exploration Operating Co) | Galal, Alaa (BP Exploration Operating Co) | Slim, Teddy (BP Exploration Operating Co) | Hughes, Andrea (BP Exploration Operating Co) | Morris, Lyndsay (BP Exploration Operating Co) | Ramsay, David (BP Exploration Operating Co) | El-wakeel, Wael (BP Exploration Operating Co) | Mubarak, Hussein (BP Exploration Operating Co) | Smith, Jeffrey (BP Exploration Operating Co) | Munger, Robert (BP Exploration Operating Co)
Giza Fayoum Completions was the second campaign of the West Nile Delta project. The campaign consisted of eight cased-hole gravel pack subsea wells. The Giza Fayoum campaign was sanctioned in August 2017 with an execution start date five months later. In this time, the well designs were finalized, downhole completion equipment manufactured, and the execution plan approved. A high rate water pack sand control technique was designed to deliver an estimated production rate of 120 MMscf/d / well. It was planned to deliver eight wells over a period of 5 months from Q1 2018 giving an average of two and a half weeks per well. Seven of the eight wells were cleaned up through a large bore completion landing string system. Each well was flowed to high rate temporary well test equipment installed on the DP semi-submersible rig to a gas rate of 65 MMscf/d, with PLT logs conducted.
This successful, fast-paced campaign is the result of applying lessons learned from the former campaign; Taurus Libra and identifying additional efficiencies that would improve performance. The design similarities between the two campaigns permitted the team to extend the learning curve and deliver superb performance on Giza Fayoum.
As for safety performance, the campaign was delivered without any lost time incident. A rigorous approach to continuous improvement resulted in reducing the completion time to 12 days per well (not including rig move, de-suspension and suspension activities). The optimized bean up procedures supported by PLT data made it possible to reduce greenhouse emissions by 20%. The sand control technique resulted in a significant reduction of total skins. Moreover, the team succeeded in delivering the wells safely, ahead of plan and under budget while adhering to BP's overarching strategy of delivering safe, compliant and reliable wells.
The efficiencies, safety culture and technology used during this campaign are now being set as the standard for future campaigns in Egypt and beyond.
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.
Several aged oil wells in offshore oil field are drilled in a conventional method. These wells are subjected to Casing-Casing Annulus (CCA) problems that might appear during the production operation and/or the shutdown phases. A continuous monitoring is performed to avoid issues related to well integrity and safety. The expected source of Casing-Casing Annulus (CCA) problem is mainly due to poor primarily cementing placement into the outer-casing strings especially across shallow aquifers formations. Due to long shutdown period on subject wells, these wells are encountered with high rate of CCA phenomena among other wells. An immediate mitigation action is required to resolve the issues by applying rig workover operation which is considered highly cost approach with low success rate. The rig workover operation results might lead to suspension or abandonment of these wells. The impact will affect the production target and the oil recovery around the area.
A new methodology approach was selected using chemical sealant recipes as a rigless operation to repair CCA problem with cost-effective and safe manner for first time in offshore filed. Based on the wellhead and annuli survey, the bleed down and build up tests were conducted and followed by close monitoring on suspected wells, which revealed sustained casing pressures and fluid return at the surface. Several fluid samples were collected and analyzed in the lab. Based on the findings, the procedures and the proper design were conducted to inject the chemical sealant into connected cement channels behind casing strings. Curing time and injection rate with required volumes of chemicals were considered based on the pressure responses and chemical performance.
The results from the rigless operation job utilizing the new approach showed wide-ranging success rates based on well by well cases and conditions such as 1) Age of the well, 2) Sustained pressure observed at the surface, 3) Injectivity rates, 4) Chemical additives volume and 5) Downhole conditions (pressure / temperature).
The new technique added a great value on restoring the well integrity and saving the rig operation cost. In addition, the approach contributed to achieve maximum sustainable production target through ensuring the well operability and reducing the production down time. Challenges, methodology, work schedule, risk assessment, lessons learned and findings have been covered in this paper.
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 (