ABSTRACT: The rapid growth of the North American shale gas industry has been made possible through technology advances in extended-reach horizontal drilling and multistage hydraulic fracture stimulations. However, the injection of large volumes of fluids during hydraulic fracturing have also raised concerns regarding related induced seismicity. Several recent empirical and numerical studies have investigated the effects of operational factors such as injection volume and rate on the magnitude distribution of induced seismicity events; studies on the influence of geological factors are more limited. A key geological factor is the influence of rock mass stiffness. Results are presented here investigating the effects of a stiffness contrast between adjacent formations on the magnitude distribution of induced seismicity events. A representative scenario based on the Montney play is modeled using a series of 3-D distinct-element simulations. Results show that triggered slip displacements across a fault that transects a stiffness contrast boundary are non-uniform, and that the larger slip displacements (and induced seismicity events) occur in the formation with the higher stiffness. This helps to explain observations of induced seismicity below the formation targeted by hydraulic fracturing.
In recent years, certain regions across Canada and the United States have experienced a significant increase in seismicity relative to historical baselines (Keranen et al. 2014; Ellsworth 2013; Farahbod, Kao, Walker, et al. 2015; Farahbod, Kao, Cassidy, et al. 2015). This increase has been linked to hydraulic fracturing and deep wastewater disposal wells associated with the development of new unconventional oil and gas resources (Horton 2012; BC Oil and Gas Commision 2012; BC Oil and Gas Commission 2014). The hydraulic fracturing process involves pumping fluids under high pressure into sections of a wellbore to generate fractures in order to increase the permeability and stimulated volume of the reservoir rock. At the same time, this injection of fluids into deep formations also serves to create localized increases in pore pressures, which in the presence of a critically stressed fault, can act to reduce the effective normal stresses acting on the fault, resulting in slip and induced seismicity. The generation of seismicity has raised public, industry, and regulator concerns in affected regions. For the most part, the events generated have very low magnitudes (< M3). However, there have been incidents of larger earthquakes (>M3) that in cases involving higher population densities and sensitive ground conditions have resulted in damage to infrastructure and property (Tagliabue 2013). To properly assess a targeted formation for induced seismicity hazard potential, it is important to study the factors that influence the triggering of fault slip and range of possible event magnitudes.
Hooshmandkoochi, Ali (Seven Generations Energy Ltd.) | Shirkavand, Farid (Seven Generations Energy Ltd.) | Prokopchuk, Richard (Canamera Coring) | Osayande, Nadine (Weatherford) | Yousefi Sadat, Ali (Weatherford) | Minhas, Arminder (Halliburton)
One of the most important hydrocarbon resources in the Western Canadian Sedimentary Basin (WCSB) is the Montney tight shale formation, which extends approximately 55,000 square miles from northeast British Columbia to northwest Alberta. Operations in the Alberta deep-basin Montney have proven this area to be one of the continent's most productive unconventional resource plays. As part of the field development plans, cores are cut from the reservoir rock to directly measure source rock properties through analysis of core samples and calibrating wireline logs with data extracted from the core samples.
The subsurface geology of the upper hole section in this particular area is complex, where reactive, swelling, and fissile shale as well as coal beds and lost-circulation zones extend across 2700 m of the openhole section. As such, historically in this field, the Montney has been cored using a weighted oil base system incorporating water contamination into the core; if zero water contamination is mandated, casing is run into the reservoir ahead of the coring section to allow coring with base oil, which leads to smaller core sizes. Additionally, coring operations can require several days when conventional coring technology is applied because of the multitude of necessary trips into and out of the hole.
Well engineers applied a systematic approach to achieve new targets by incorporating the latest available technologies and drilling techniques in the industry into a coring program while also optimizing well structural designs by minimizing use of casing strings. This allowed achieving the project's primary objectives of cutting larger-sized cores with no water contamination using minimal planned trips.
This paper discusses how managed pressure drilling (MPD) and wellbore strengthening techniques, as well as new coring technologies, were analyzed, planned, and incorporated into this project. This led to the successful execution of an optimized, cost-efficient well structural design with 100% core recovery and no water contamination while. At the same time, a new record was set in terms of the longest core length cut in one run in onshore North America.
Recent focus in exploitation of unconventional hydrocarbons like shale gas and shale oil have brought numerous exploration and production challenges worldwide. Unconventional exploration of hydrocarbons, over the past decade has seen a lot of improvement in use of multi domain technology like inversion geophysics, petroleum systems modeling, reservoir characterization, fracture geomechanics and production stimulation. However, identification of sweet spot for drilling wells is one aspect of the unconventionals, production of hydrocarbon is another major challenge which industry faces. Due to lack of integrated studies, a well drilled in a shale reservoir can end up in producing little or no hydrocarbons, or can have rapid decline rate of hydrocarbon production. Till date no attempt has been made to combine inversion geophysics, petroleum system modeling, fracture geomechanics and production optimization to make an integrated earth model, which can predict the sweet spots and help in predicting production optimization scenarios in shale reservoirs. In this study, an integrated workflow has been developed, which combines all three domains (Inversion Geophysics, Petroleum System Modeling & Reservoir Engineering) in a systematic manner, which can help in robust exploitation of sweet spots to generate optimum production profile which is economically most viable. In addition to the novelty of integrating seismic, basin modelling and reservoir engineering; this invention involves optimized hydraulic fracture (HF) design and production performance generated from an unstructured grid. Combination of hydraulic fracture optimization on an unstructured grid with sweet spot and natural fracture propagation by seismic inversion and basin modelling workflow, further strengthens the novelty of the workflow.
This paper presents the design, current status and future expansion plan of the waterflood scheme in the Girouxville East Lower Triassic Montney reservoir, which is located about 350km north-west of the city of Edmonton, Alberta, Canada (
A small water injection pilot was initiated in October 2013 with a single water injector to alleviate reservoir pressure depletion in the local area. The results were encouraging, and the project has been expanded to a larger scale waterflood scheme in 2015, which currently consists of 6 horizontal producers and 4 horizontal water injectors. A 388 ha (1½ sections) waterflood expansion was designed based on comprehensive geological and engineering evaluations. A detailed geomodel was created with available core data, well petrophysical analyses, horizontal well geologic descriptions and seismic data in the area; the Montney formation was subdivided into 4 coarsening-upward cycles, with 6 facies identified within. Dynamic reservoir simulation was initiated by importing data from the geomodel. Reservoir and well properties were fine-tuned with a high-quality history. Multiple forecast scenarios were run to determine an optimal waterflood recovery scheme.
Within half a year most offsetting oil producers have shown positive response to water injection with an increase in total fluid and gradual decrease in the producing gas-oil ratio (GOR). The oil rate decline has slowed down significantly with anticipated incremental oil recovery of 5 – 7% OOIP over the primary depletion. Further expansion has been identified in the oil-leg of the surrounding sections. The waterflood design will focus on down-dip injection to maintain more gravity stable injection water fronts along the field oil-water contacts for optimum pressure support and oil displacement.
The paper describes the reservoir management experiences of Kerisi field after seven years of production. Kerisi field is located in Block B of South Natuna Sea and comprises five separate reservoirs in three geological zones.
Forty seven percent of the reservoir hydrocarbons are located in the Upper Gabus Massive West (UGMW) reservoir; optimum production from this formation is expected to be reached by injecting gas at the gas cap. The source of injected gas is from all five Kerisi reservoirs and the nearby Hiu field. The liquid hydrocarbon production from UGMW and the production/injection of Kerisi – Hiu produced gas in this formation is of high importance to the future development stage of Kerisi – Hiu field.
The initial reservoir management strategy was to optimize oil value with injection while meeting gas sales requirements. Both gas sales commitments and injection targets were honored with high Kerisi – Hiu production and the strong performance from other gas fields.
With time, other gas fields became depleted faster than expected. Thus, it was decided to reduce gas injection rate in UGMW and produce more Kerisi and Hiu gas to increase gas sales volumes. The reduced of injection rates improved short term economic of the fields, but the effect to reservoir and long term economic benefit still needs evaluation.
This paper will (1) show the impact of varying injection rate at UGMW to the overall Kerisi – Hiu field future production, include oil, gas, condensate, and LPG, (2) discuss an updated – improved reservoir management strategy, and (3) present an economic evaluation of the updated reservoir management strategy for the Kerisi – Hiu fields.
The purpose of the paper is to share lessons learned in the evaluation of historical performance, data acquisition and monitoring, static and dynamic modeling, history matching, prediction of future performance, and the dynamics of reservoir management strategy which support future profitable opportunities.
Identifying subtle faults at or below the limits of seismic resolution and predicting fractures associated with folds and flexures is one of the major objectives of careful seismic interpretation. With the common use of 3D seismic in the late 1980s, 1
Bellis, Chris J. (Frontier Engineering Ltd.) | Bothwell, Paul D. (Alberta Energy and Utilities Board) | Burke, Lyle H. (APA Petroleum Engineering Inc.) | Grace, Robert D. (GSM Inc.) | MacDonald, Ron R. (APA Petroleum Engineering Inc.) | McLellan, Pat J. (Advanced Geotechnology Inc.)
This paper reviews the history of the world's largest running blowout as well as the integrated engineering based approach taken to define the blow-out mechanism and to ultimately kill and abandon the wells.
During 1916 cable tool drilling operations, Peace River Oils No.1 encountered an uncontrolled flow of salt water and gas at 345 m depth. The flow was estimated at over 30,000 bbls/d, ultimately the rig collapsed into the sinkhole and temporarily killed the surface flow. The rig was rebuilt in 1917, recovered the production casing, but again a blow-out could not be controlled and the well was left to flow 30,000 bbls/day of salt water into the Peace River. At the time of the project initiation, there was one relief well (1955), one attempted relief well (1982) and a lost well (1916).
The defacto well operator, the Alberta Energy and Utilities Board contracted an integrated team of professionals including well control engineers; geologists, drilling and completion engineers, geomechanics specialists and well operations specialists to evaluate the potential of effecting a permanent kill solution. This led to a primary recommendation to re-enter the 1916 wellbore via a flowing well operation to reach total depth and conduct a well kill.
The kill operation was complicated by having no production casing within the 1916 wellbore, shallow underground flows with multiple break-outs around the three wells, collapsed and parted casing in the 1955 well and entrained sour gas. The uncertainty of achieving access to the various wells to total depth and preparing for a wide range of potential well kill volumes and rates, were primary concern, as were the environmental constraints of operating on the unstable banks of the nearby Peace River.
In the early nineteen hundreds, numerous wells were drilled along the banks of the Peace River in Northern Alberta, Canada. Cable tool rigs were used to drill where natural gas and oil seeps were evident along the riverbank. River barges would transport the heavy rig components to well sites where no surface access existed.
In October 1915, the Federal Government of Canada issued Lease #12038 under the Dominion Land Act, giving the Peace River Oil Company approval to drill for hydrocarbons at 04-31-085-20W5M. This location is 480 km (300 miles) Northwest of Edmonton, Alberta near the town of Peace River. Peace River Oil Company No.1 was spudded roughly 30 m from the edge of the Peace River on April 15, 1916 Drilling proceeded to a depth of 345 m (1132 feet) where a major uncontrolled saltwater and natural gas flow (blow-out) was encountered, resulting in the wooden derrick collapsing over the well. Attempts to rebuild the derrick in 1917 and control the saltwater flow were unsuccessful and eventually the 4-31 well was left to flow 30,000 bbl/day of saltwater and gas into the Peace River.
No preview is available for this paper.