The Slave Point platform was initially targeted for conventional production by means of vertical wells in the early 1980s. Success was marginal because of the unpredictability of localized porosity development. As a result, the full-scale commercial development of this resource was deemed uneconomic because of poor reservoir quality. More recently, however, horizontal-drilling and multistage-fracturing technology has allowed operators to open up lower-porosity horizons to improve flow capacity, to improve recoveries, and to allow for commercial development from zones previously deemed uneconomic.
The Slave Point has a greater thickness and is less permeable than other tight-rock plays in Alberta, such as the Cardium and Viking. It produces high-quality, light oil with low water- and solution- gas-production rates. Despite high estimates of original oil in place (OIP) of approximately 3 to 10 million bbl per section, horizontal-well rates are still challenged because of the lower permeability through the pay section. In this regard, the continued deployment of innovation and technology has been critical in improving well-production performance, compressing project costs, and ultimately optimizing project economics.
The focus of this paper is solely on one of the major Slave Point operators who has drilled 49 horizontal wells that account for 200 000 m (656,000 ft) drilled and 1,350 fracture stages in the Evi and Otter Slave Point fields since 2008. This operator has continually deployed advancing technologies to improve project economics. The information will be presented in terms of the influence of technology on well design, the optimization and deployment of the various technologies, and the demonstrated improvement on productivity and reserves recovery. The discussion will focus on three development phases that highlight the progression from vertical to horizontal technology:
· Vertical Appraisal
· Single-Lateral (SL) Development
· Dual-Lateral (DL) Development
The case studies presented will demonstrate clearly the production impact from the use and application of these technologies. The methods and lessons learned through the use of DLs, openhole junctures, and openhole multistage systems can be applied to other unconventional formations.
Emerging, horizontal multistage-fracture technology has played an instrumental role in allowing for the economic accessibility of unconventional tight-rock resource plays. The increasing development of the Slave Point platform, in northwestern Alberta, provides an excellent demonstration of the rapid advancement of this technology and the resulting continuing improvement in project economics. The focus of this paper is limited to the Evi and Otter fields (Fig. 1). Although other Slave Point unconventional fields are now in the midst of applying horizontal multistage-fracture technology, the original and most-robust development to date has transpired in the Evi and Otter fields.
The Slave Point formation is a fringing reef complex that built up along Pre-Cambrian highs during the Middle Devonian. The Slave Point conformably overlies the Fort Vermilion evaporites and consists of four distinct fore-reef to off-reef cycles recognized in core (Fig. 2) and on well logs (Fig. 3), and it is unconformably capped by the Waterways and Ireton shales.
· Cycle 1 directly overlies the Fort Vermilion and consists primarily of off-reef limestones. The uppermost part of the cycle is the primary target for development and is considered to be a widespread shallow-water ostracod-peloid-bearing grainstone that formed on a broad marine shelf in low to moderate energy. Porosity and permeability average 6% and 0.4 md, respectively. At the base of this cycle, a thin (less than 1 m), wavy, laminated dolomite bed can locally occur as a result of pervasive matrix dolomitization, enhancing porosity and permeability to 19% and 13 md, respectively.
· Cycle 2 abruptly overlies Cycle 1 and represents a fore-reef deposit sourced from the Evi reef-building fauna to the southwest (Fig. 2). Facies consist of nodular limestone at the base and clean limestones at the top that are abundant in brachiopods, corals, and transported bulbous/massive stromatoporoids. Cycle 2 core data suggest average porosity and permeability of 6% and 0.2 md, respectively.
· Cycle 3 abruptly overlies Cycle 2 and primarily consists of off-reef, brachiopod-rich nodular limestones. An average porosity of 3% and a permeability of 0.05 md have been calculated from limited core data over this facies. Close to the Evi-reef margin, a deposit of grainstone at the top of Cycle 3 has also been identified. This has a 6% porosity with a permeability of 0.4 md and, although restricted in area, can significantly affect OIP per section.
· Cycle 4 is composed of off-reef, brachiopod-rich nodular limestones with a porosity and a permeability of 3% and 0.05 md, respectively. Cycles 3 and 4 thin dramatically from west to east and, for the most part, are deemed non reservoir.
The Slave Point Evi field was initially discovered in 1981 when a vertical well was drilled that targeted a Slave Point thick or “carbonate reef buildup.” This initial discovery prompted the successive drilling of 12 vertical wells during the next few years, specifically targeting the reef facies in which ample porosity and permeability development existed to fuel this conventional play.
In 1983, an off-reef, Pre-Cambrian seismic high was targeted and completed in the Granite Wash sands underlying the Slave Point carbonate platform. This discovery led to the drilling of more than 120 wells within the Otter/Evi area. Though the Granite Wash was the primary target, the Slave Point platform (off-reef) had displayed oil and gas shows in drill cuttings and on logs, which suggested that this resource (west and updip of the Evi Slave Point reef) was, in fact, oil-charged. The large number of Slave Point penetrations proved later to be a very important resource because they allowed operators to study the Slave Point on logs at very little cost.
Although oil shows were consistent across the Evi and Otter fields, log analysis curtailed optimism because porosity development was not robust enough to meet general cutoffs for conventional vertical plays. It did, however, outline that the resource was widespread in the area, was consistent and uniform in thickness, and had substantial OIP when porosity cutoffs were lowered to nearly 0%.
The initial Slave Point platform recompletion occurred in 1983 and started multiple series of vertical tests until current day. A total of 47 vertical test wells, including recompletions and new drills, has been completed in the Slave Point.
With the evolution of horizontal-drilling technology initially deployed by industry in the early 1980s, horizontal wells were drilled into lower-permeability resources to enhance reservoir contact and to improve inflow. Although enhanced reservoir contact was achieved “by the drill bit,” unstimulated-horizontal-well performance was similar to that of hydraulically fractured vertical wells. It became evident that, in unconventional resource rock, the artificial creation of reservoir permeability was required to enhance well productivity. With learnings from years of fracturing technology being successfully applied to vertical wells to improve reservoir contact and to create the required permeability, industry operators and service providers recognized an opportunity to use this technique in horizontal applications.
Operators began to experiment by applying hydraulic-fracturing techniques to horizontal wells. The most simplistic approach involved bullhead techniques without any diversion. Productivity improvements were demonstrated when compared with unstimulated horizontal wells; however, the technique left plenty to be desired because the fracture would generally initiate at one point along the horizontal lateral and leave the remainder unstimulated (Warpinski et al. 2005). Industry operators were keen to find a more-effective method that would allow for stimulation along the entire length of the horizontal wellbore.
The initial attempts with multistage fracturing were limited, very costly, and very inefficient; however, through a dramatic increase of horizontal-well development from 2006 to 2009, the continued refinement of this technology evolved, and fracture placement efficiencies were improved. Horizontal openhole multistage (OHMS) fracturing technology was initially developed and deployed in the early 2000s (Seale et al. 2006; Seale 2007). This technology allowed for the mechanical isolation of zones along the wellbore to successfully place several isolated fractures, ultimately enhancing the well’s flow capacity.
With the data that existed from vertical wells in the Slave Point area as a result of the Granite Wash development, the geology of the Slave Point was very well understood and was deemed an ideal candidate for exploitation by means of horizontal multistage- fracturing development. In 2006, the first horizontal well was drilled in the Slave Point area, with great success. From that time forward, into 2011, a combined 230þ horizontal multistage-fractured wells were drilled in the Evi and Otter fields. Through this time of rapidly increasing exploitation of the resource, new and improved technologies were continually deployed to improve the profitability of these horizontal wells further.
In late 2011, this operator drilled the first dual-leg horizontal well into the Evi/Otter Slave Point region. Although technology and techniques to drill dual-leg wells had been available and deployed in conventional resources since roughly 2008, the ability to run OHMS systems in DLs was still an emerging technology. These combined technologies now allowed operators to drill and multistage fracture two separate legs, effectively doubling the reservoir contact and flow capacity of one well. In addition to well-productivity improvement and reductions in both per-lateral costs and surface and infrastructure requirements, environmental impacts were realized and ultimately program economics improved.
Since the initial dual-leg well was drilled in the Evi/Otter area, this operator has drilled an additional 25 DL producers into the area while continuing to deploy optimization initiatives to improve well costs, cycle times, and operational efficiency.
Normalization of Data
To draw fair comparisons between data sets, production and cost structures presented throughout this paper have been normalized:
· Production data (daily rates and cumulative) are presented in a normalized format in which average monthly data of each well start on month zero of production.
· Cumulative-production data are plotted during a shorter period of time compared with daily rates to display a time period in which a constant number of wells is producing.
· Plotting of average production data per fracture stage takes daily rates and cumulative data per well and divides by the number of stages successfully fractured. In cemented-liner (CL) abrasive- jetting completions, the number of fracture stages is equal to the number of perforated intervals.
Phase 1—Vertical Appraisal
In conjunction with the Evi and Otter off-reef Granite Wash development in the early 1980s, operators were intrigued by the uphole potential of the Slave Point platform. Several operators vertically tested and completed the off-reef carbonate facies targeting the grainstone horizon(s). A total of 47 wells was completed and brought on-stream from 1983 to the current day.
In most cases, the Slave Point was a secondary target and was completed following the abandonment of the underlying Granite Wash sands. Typically, the Slave Point was found to require stimulation to enhance inflow as a result of the poor reservoir quality of this unconventional resource. Various stimulation techniques were used successfully to enhance inflow. However, in most cases, the success was merely technical because production enhancement did not economically justify the capital requirement. Understanding the deliverability of a stimulated vertical well was later instrumental in predicting horizontal-multistage-fractured-well inflow.
The production results are summarized here and displayed in Fig. 4. The wells were separated into two distinct data sets:
· Unconventional Resource
Inflow from these wells is generated from the low-permeability grainstone and coral-bed horizons with average permeabilities less than 0.5 md. In these instances, vertical wells have displayed initial production (IP) rates of more than 20 B/D; however, on average, an IP at 12.5 B/D following stimulation provides recoveries up to approximately 15,000 bbl.
· “Hybrid” Unconventional Resource
Vertical wells with higher productivity display double to triple the IP rates of the lower-productivity wells, and reserves recoveries ranging between 30,000 and 110,000 bbl. The difference in well productivities is attributed to a thin, dolomitized layer with high permeability found at the base of Cycle 1, which extends through a narrow corridor over the Evi and Otter area. It is recognized that the major unconventional prize lies within the low-permeability resource rock, and with this vertical deliverability information in hand, a more-effective prediction of horizontal, multistage fracturing was possible.
Phase 2—SL Development
In 2006, the first Slave Point horizontal multistage-fractured well was drilled and brought on stream in the Evi field. The results demonstrated a dramatic step change in productivity improvement compared with stimulated vertical wells.
Two different technology approaches were being applied in the Slave Point—CLs using abrasive-jetting technology and OHMS systems using mechanically set packers with hydraulic and ball-activated ports. Each system came with its own set of pros and cons.
Operators began to deploy both CL and OHMS-system techniques as continued horizontal appraisal of the resource base and technology proceeded in parallel. Although productivity improvements were dramatic, the high-cost structure of these operations kept economics at marginal levels. The question was, Does increasing the number of fractures per lateral have a measurable impact on reserves recovery and well productivity? The answer determined was “Yes”. The testing of increasing stage density was under way and is still evolving toward defining the optimal spacing.
The general well design deployed was (Fig. 5):
· Surface casing is set to a depth as required by government regulations.
· Intermediate casing was landed horizontally and set into the top of the Slave Point.
· Average lateral lengths were approximately 1390 m (4,560 ft).
Several lessons were learned through drilling the initial set of horizontal appraisal wells:
· Two highly permeable zones uphole caused added drilling days as a result of lost circulation. One well was abandoned because of severe losses and gas uptake.
· Obtaining build rates through the Ireton shale was challenging.
Through the transition of horizontal appraisal to development, a number of optimization initiatives were implemented. Some of the key lessons/efficiencies were:
· Bit optimization to improve penetration rates throughout each interval and to minimize bit trips.
· Bottomhole-assembly (BHA) optimization to improve directional performance/reliability and to obtain reliable build rates. Reduced cycle time in pad-drilling scenario was achieved by drilling with two rigs concurrently. Time savings achieved through this was approximately 60 days per pad.
· Consistent well program reduced average well costs by spreading large rig and equipment mobilization/demobilization costs over numerous wells.
The drilling-performance improvements, from the appraisal- to the development-drilling phase, are displayed in Figs. 6 and 7. The results are summarized here:
Additional time incurred on the initial appraisal wells was a result of:
· Capturing Slave Point core
· Running openhole logs
· Cementing operations on CL systems.
Realized-performance improvements, from appraisal to development, were:
· A 20% improvement in well costs
· A 25% improvement in cycle time (120 to 160 m/d; 395 to 525 ft/D).
Through SL appraisal and development phases, there were two different completions technologies deployed: CLs and OHMS systems. The following discussion provides insight into both the evolution of the system capabilities and the execution successes and limitations experienced with the use of each system.
The initial two horizontal wells were drilled and completed using OHMS systems with seven stages. However, because competitor operators in the area successfully deployed CLs with abrasive jetting, it was decided to proceed with a small five-well program to test the methodology and also to test the impact of increasing the number of stages per lateral. A typical CL completion with abrasive jetting is shown in Fig. 8.
CLs with abrasive jetting were initially deployed because of these advantages:
· Attractive, upfront equipment costs vs. the options available for OHMS systems at the time.
· The emerging abrasive-jetting technology had been trialed in other unconventional horizontal plays, and it had demonstrated a series of successes.
· Pumping with coiled tubing (CT) reduces cleanout costs.
· With a single point of a fracture initiation, it is assumed that a better fracture can be achieved.
· Full-wellbore access is available at the conclusion of the stimulation, making this option attractive for optimization and enhanced-oil-recovery flexibility.
The summarized operational procedure is:
· A 114.3-mm (4.5-in.) liner is cemented in the horizontal section and tied back into the 177.8-mm (7-in.) intermediate casing.
· A 114.3-mm fracture work string is run into the liner hanger, and wellheads are isolated with 70.0-MPa valving at surface.
· By use of CT and a packer/abrasive-jet assembly, the tool can be set at the point at which the fracture is to be placed. Sand is pumped down the CT to cut through the casing and into the formation with the abrasive jet. This is followed by the pumping of the main treatment down the liner annulus.
· Multiple stages can be stimulated by releasing the packer assembly and moving uphole.
· Crosslinked-gel, water-based fluid systems are pumped with 20/40-mesh sand.
· 30 t of 20/40-mesh sand was pumped per stage.
Although the system had demonstrated successes and maintained certain advantages, there were some drawbacks to this method:
· The ExxonMobil patent restricted the number of stages to six with a 3% royalty if the horizontal section was less than 1525 m (5,000 ft). The true vertical depth of the Slave Point is in very close proximity to the 1525-m cutoff.
· Fracture-stimulation setup times are longer with the addition of CT and associated equipment. There are also extra costs associated with the abrasive-jet tool. With the single initiation point, it is assumed that better fracturing is achieved, although the benefit of production contribution from an openhole lateral and natural fractures is eliminated with CLs compared with OHMS systems.
· Setting issues became a problem, and several delays were encountered because of faulty downhole abrasive-jet tools. The round trip to replace the tool was close to 8 hours.
· An extra 10 m3 (63 bbl) of water per stage was required to abrasive jet the casing/formation.
· Pumping rates were limited to 3.5 m3/min because of frictional pressure loss as the job is pumped down the annulus.
· Although not a direct fault of the CL abrasive jetting, sand-production issues caused numerous pump-and-rod failures.
As OHMS-system technology advanced with increasing-stage-count capability and slight easing of the cost structure, in late 2010, the system was chosen as the preferred application for a series of multiwell pads. A typical OHMS system is shown in Fig. 9. The OHMS system was used with 14 and 20 stages per lateral with the intention of increasing well productivity and accessing additional reserves.
A summary of the technology and operational procedure is:
· The OHMS system is generally installed from a drilling rig and is composed of a string of casing/liner run through the entire horizontal section with a series of openhole packers and fracture ports.
· An initial actuation ball is dropped to a toe sleeve to close the system off from the annulus, allowing pressure to build, which sets the mechanical packers along the system.
· The fracture port in the first stage of the liner needs to be hydraulically opened to allow pumping to start, followed by continuous pumping.
· A series of incrementally larger balls dropped from the surface through a ball-dropper system activates the fracture ports from toe to heel to provide access to the openhole. Locking devices have been engineered into the fracture ports to ensure they remain open.
· The activation balls act in two ways—to open the ports (first) and to provide internal isolation for the previous stages already stimulated (second).
It is important to note that, upon the inception of the technology, the system had only an 11-stage capability in a 4.5-in. liner because the ball sizes were constructed in 1/4-in. increments. Through the last few years, service providers have released new 1/8- and 1/16-in. increments, allowing for more potential stages per well and the ability to pump larger balls through the entire lateral. The significance of this is discussed later.
The obvious advantages of the OHMS systems are:
· OHMS systems allow for production from the openhole portion of the reservoir. Because the entire annulus is under pressure, existing natural fractures and induced microfissures can open and contribute to production, as well as create a more-complex near wellbore fracture network. Although this contribution may become less significant in ultratight rock (Augustine 2011), because of the considerable heterogeneity in carbonate formations, this technology allows operators to take advantage of localized porosity development, such as the thin, dolomitized streak at the base of Cycle 1 in the Slave Point.
· Pumping time is reduced because of the continuous stage-to-stage pumping and the use of a wellhead ball-drop system.
· Total-job fluid requirements are reduced by approximately 15% because a stage-to-stage fluid volume (flush) is calculated to determine when the ball should be launched so that it seats and isolates the next stage just as the flush fluid reaches the preceding ball seat. In this way, the flush of the preceding stage becomes the pad for the next fracture initiation. The impact of this on reducing costs compounds in the winter when all fluids are required to be heated before pumping.
· A 20-stage system can be pumped in 1.5 days. At 5.0 m3/ min, a 30-t stage can be completed in 20 to 25 minutes. This represents a 60% improvement in pumping cycle time.
· No acid is required to assist in fracture initiation, whereas it is required in many CL scenarios. Although the cost structure was slowly improving on OHMS system operations, a continuous effort was placed on implementing further optimization initiatives.
· Liner systems were designed to use the largest balls possible while still achieving the desired stage-count capability. This allowed for CT access to the toe of the well to perform cleanout operations in the case of a screenout. Deploying 1/16-in.-increment ball seats has allowed for this in 20-stage applications when in the past, in the past, a screenout at a toe stage may have meant the loss of four to five of the toe stages.
· In an attempt to alleviate post-stimulation sand flow into the lateral, 5.0 t of 20/40-mesh resin-coated sand has been included and is tailed in at the end of each stage. Resin-coated sand has proved to be an effective method of sand control.
· Low-density sand scours were introduced into the early phases of the sand ramp to assist with fracture initiation.
Figs. 10 and 11 display costs normalized on a per-stage basis and display comparisons between CL/abrasive-jet and OHMS-system technologies through time. Here is a summary of some noteworthy observations:
· The initial two wells completed with OHMS systems in 2007 should be considered statistical anomalies because these fracture operations were impacted by the operator’s limited knowledge with regard to specific fluids and proppants required to efficiently fracture the Slave Point. The low completion efficiency denotes this challenge and is not believed to reflect hindrances in the technologies. All learnings from these wells were applied in future fracture designs going forward.
· With increasing stage counts, completion costs on a per stage basis demonstrate an improvement because of (for example) the deleveraging of each stage to the capital associated with the rig-prep work, and equipment rentals.
· Per-stage costs were compressed through time as operations logistics were improved and fracture designs were optimized.
Production results displaying the impact of completion technology and increasing stage counts are outlined next. As a result of the limited number of data points used in this analysis, the results concluded are solely qualitative.
CL and OHMS Technology
After normalizing on a per-stage basis (Figs. 12 and 13), the production data demonstrate superior productivity from OHMS systems (it is noteworthy that only seven- and fourteen-stage wells were used in this comparison to reduce the impact of stage spacing on productivity). The results are summarized as:
· A 60% improvement in IP rates.
· A 40% improvement of reserves recovery during the initial 6 months.
It could be inferred that the improvement in productivity is likely attributed to the additional inflow provided by the openhole portion of the reservoir that results from use of the OHMS technology.
Increasing Fracture Density
18 SL OHMS-completed wells [approximately 1300-m (4,265-ft) laterals] were used in this data set. Production was normalized on the basis of the starting month and calculated on a per-stage basis (Figs. 14 and 15). A summary of the results is presented in Table 1. With increasing stages per lateral, the following is clearly displayed:
· Improved flow capacity positively affects production rate and reserves recovery.
· Well rates flushed off with high-decline profiles toward a production rate of approximately 60 B/D. This marks a significant transition from high-rate decline-flush production to low rate decline dominated by flow contribution from existing matrix permeability. This wedge is demonstrative of the well storage capacity generated by the fracture geometry and is directly reflective of incremental reserves recovery with an increasing number of fractures.
It should be noted that several of the 20-stage wells were equipped with casing gas compressors (CGCs) after 6 or 7 months of production, which reduced backpressure on these wells and optimized well productivity.
Production was also normalized on a per-stage basis to evaluate the impact of potential competitive drainage between the fractures with increased density (Figs. 16 and 17). The findings are:
· As anticipated, the inflow capacity per fracture stage demonstrated a degradation of inflow when stage density was increased. This result is a result of the reduced drainage area and potential, competitive drainage between stages. However, the cumulative outcome or total well-flow capacity, as demonstrated previously, improves with the total number of stages, even though the production efficiency of each stage is reduced.
· Average cumulative production of the seven-stage wells after 6 months was approximately 18,000 bbl in comparison to 24,000 bbl (approximately a 30% increment) in 14-stage wells and 27,000 bbl (approximately a 13% increment) in 20-stage wells, before installation of CGCs.
· Understanding the preceding findings is critical when it comes to evaluating the improving or diminishing economic return with increasing stage counts.
The production results from the preceding analyses demonstrate these conclusions:
· Within the Slave Point platform, OHMS systems have demonstrated inflow-capacity benefits compared with CL technologies.
· Increasing the fracture density, or the number of fractures along the lateral, has demonstrated incremental flow capacity and reserves recovery.
· While increasing the number of stages per lateral improves the total well’s production outcome, a degradation of inflow is observed and indicates that the inflow-per-fracture contribution is decreasing because of competitive drainage or communication effects between stages.
· The economic impact of increasing the number of stages needs to be evaluated to ensure economic value is being maximized.
Phase 3—DL Development
As demonstrated in the preceding section, the ability to effectively fracture stimulate horizontal wells significantly rejuvenated the economics of unconventional reservoirs. Although technology aided in dramatic improvements to economics, margins remained low as a result of the high capital structure, leaving project viability susceptible to unfavorable swings in commodity pricing. For that reason, in early 2011, other options were evaluated to improve program economics.
Project economics in SLs showed measurable gains when stage density was increased on a per-lateral basis; however, at 20 stages per well [approximately 1300-m (4,265-ft) laterals], the economic gains were diminishing because of communication between stages. The obvious concern with deploying more stages, beyond 20 per lateral, was the potential to take a step back by overcapitalizing and eroding economics from the current value that was being generated. As a result, a more dramatic shift in innovation was required. The concept of drilling a second lateral to improve inflow was considered.
DL drilling and multistage-fracture technology had been successfully coupled by only a few operators in North America because of the enhanced complexity of the operation, increased capital requirement on a per-well basis, and the stability of the reservoir rock required to withstand unsupported openhole production without sloughing. If successful, however, a DL well design could allow for enhanced capital leverage on one main host wellbore from the surface to effectively drill and complete two multistage-fractured laterals at a significant capital discount. Following vigorous scrutiny, a decision was made to forge ahead with the transition from SL to DL development on the basis of the following rationale.
Improved Economic Margins
Capital efficiency was the main economic driver for the transition from SL to DL development. A DL well design allows for two separate laterals captured for a significant capital discount compared with two independent SL wellbores from the surface. On the basis of initial expectations, a DL would cost 1.65 times that of a SL and deliver 1.85 times the initial productivity than an SL well.
Improved Ultimate Recovery
Increasing reservoir contact by adding a second leg and doubling the number of fracture stages on a per-well basis decreases the economic-producing limit of the well on a per-stage basis, allowing for an extended life of the well and enhancing recovery.
Infrastructure Requirements, Operational Footprint, and Environmental Sustainability
In 2011, a pilot case study was conducted regarding well spacing. Two SL wells were drilled with 200-m (656-ft) spacing between the laterals (a downspacing from the previous development plan of 400 m). On the basis of the inflow results, limited interlateral communication was demonstrated with only a slight degradation of production per well. In addition, little impact to the production-decline profile was observed. On the basis of this information as well as several reservoir- modeling evaluations, it was concluded that a lateral spacing of 200 m, or 8 laterals per section, was required to maximize economic value (Fig. 18).
This conclusion directed development planning toward a transition from four wellheads per pad to eight, assuming continued execution of an SL development program. The impact would be significant on the operational footprint and increased surface infrastructure required (wellheads, testing facilities, pipelines, power generation). The environmental sustainability of the operation was also considered. The Evi and Otter fields are in an area that is generally forested with several sensitive bodies of water. Minimizing impact on the ecosystem in the area is critical to maintaining the sustainability of the project.
Through a transition to DL development, the impact on the operation footprint would remain unchanged (Figs. 18, 19, and 20) (Note: The field-development diagrams are not drawn to scale).
Net Reduction of Execution Risk
Drilling multilateral wells is not considered to be new to the industry; however, multistage-fracture stimulation of multiple laterals is largely seen as “new” technology. The majority of the technology and tools deployed have been repeatedly tested and proved in SL applications. One of the largest execution risks in the Slave Point development area continues to be drilling through lost-circulation zones within the vertical section of the wellbore. These high-permeability zones can unexpectedly add drilling days and additional cost. In the most severe lost-circulation cases, it has caused operators to walk away and abandon wellbores. The advantage of gaining one additional producing lateral per wellbore significantly reduces this capital risk. On the flip side, the following new risks are introduced:
· Slave Point rock properties must allow for wellbore integrity to be maintained (i.e., sloughing risk) at the openhole portion of the junction.
· When running the OHMS system into the second lateral, although proved unlikely, there is the risk that the system may become stuck within the well.
· Locating into the desired lateral during drilling and completion operations is necessary.
· Whipstock equipment and sidetrack complications should be considered.
Through careful analysis of these risks, it was concluded that lost-circulation zones still presented the most significant capital risk to the program.
The cycle times for full-section development are (measured in day-from-spud to on-stream):
· SL development (8 wells): 150 days.
· DL development (4 wells): 110 days.
The preceding example displays a realized compression of cycle times of approximately 25%. To date, 31 DL wells have been drilled and completed in the Evi/Otter area. The execution and deployment of these technologies are continually evolving.
Drilling Operational Progression
For simplicity and functionality, the conventional SL template was maintained. After the SL was drilled and the liner was run, two different approaches were used to drill the second leg—a whipstock/casing-window approach [Fig. 21; Technology Advancement for Multilaterals (TAML) Level 2] and an openhole sidetrack (Fig. 22; TAML Level 1).
After initial execution, the whipstock/casing-window approach was deployed to eliminate the amount of openhole section. A summary of the procedure is:
· The initial SL well was drilled as per the same well design with an OHMS system run in place [tied back into the intermediate string (i.e., no openhole section)].
· A whipstock was set in the casing, and the window was cut to initiate the second leg.
· The second lateral was drilled to total depth (TD), and the second OHMS system was run in place and set, leaving approximately 20 m of openhole section.
· The whipstock was retrieved so that both legs were accessible to completions.
Optimization initiatives implemented while drilling DLs with the whipstock/casing-window approach were:
· Intermediate-casing point (ICP) setting depth was extended farther into the Slave Point to allow sufficient spacing for a casing exit into the Slave Point upper cycle where the most-competent rock was located.
· Casing centralizers were run on the intermediate string to improve the cement job, allowing for more-effective window milling operations to initiate Leg 2.
· Directional plans were optimized in several regards:
Turns were reduced or eliminated through the build section to allow drillers to solely focus on achieving the required build. Turns were completed after the wellbore was into the Slave Point.
Tangent section set in build to land the production pump.
ICP was landed at an 858 inclination to enable finding the optimal reservoir interval without losing excessive vertical section on drillout.
All casing cuts were planned as right-hand exits.
· A less-aggressive motor setting was deployed to drill the vertical section, followed by an additional trip to increase the motor angle at the kick-off point. Ensuring the BHA was fit-for-purpose allowed for an optimized rate of penetration through the vertical and the build sections.
· Geosteering reduction through recognition that oversteering in the reservoir provided little added value for production because fracturing would compensate for being slightly off target.
· In pad-development scenarios, concurrent drilling operations were used with two sister rigs from the same contractor for synergies with crews, equipment, camps, and transportation.
After drilling 22 DL wells and identifying the critical risks in the operation, it was concluded that the use of the whipstock/casing window posed the greatest capital risk to well execution because of:
· Movement of the whipstock within the casing after being set.
· Excessive wear on the whipstock during milling operations to initiate the second lateral, causing additional trips to retrieve the assembly. The impact on well design was:
The initial OHMS system was set into the openhole rather than inside the intermediate string.
A plug was set above the liner system in Leg 1 to ensure protection from debris.
The second lateral was initiated with an openhole sidetrack bit just outside the 177.8-mm (7-in.) casing.
The second lateral was then run into Leg 2 with the aid of a bent joint on the end of the assembly, allowing the drillers to orient into the desired leg.
Another phase of initiatives was introduced to optimize well design:
· Optimization of directional plan to “tuning-fork” design, allowing for an improved ease of locating the ideal sidetrack point and allowing for improved reservoir access (Fig. 23).
· Fine tuning of the sidetrack procedure. Initial sidetracks used a dedicated sidetrack BHA and bit to initiate the second lateral. To eliminate this additional trip, the lateral BHA was run to drill the sidetrack and drill ahead to the TD of Leg 2.
The impact of the transition from the whipstock/casing-window method to openhole junctions is demonstrated in Fig. 24 and summarized here:
· Well costs reduced by 2.5%
· Cycle time reduced between Legs 1 and 2 by approximately 16%
· Inherent operational risk of whipstock eliminated Performance results from the transition from SLs to DLs are displayed in Figs. 25 and 26, and the average trends are summarized as:
Reservoir contact per well has increased 105%.
Drilled meters per day have increased by 11.6%.
Per-lateral cost has been reduced by 25%.
As noted, the majority of the technology and tools deployed in the completion of DLs have been tested repeatedly and proved in SL applications. A summary of the operational procedure is:
· The well is prepared for the fracture treatment in a manner similar to that of SL wells. A fracturing string is run into the well but with a bent joint, which enables access into the desired lateral.
· After the fracturing string is strung into the liner assembly and pressure tested, the well is fracture stimulated and cleaned up as per SL pumping conditions.
· Following the stimulation of the first lateral, a bridge plug is set above the openhole to prevent balls transferring over into the second leg and inadvertently opening a fracture port.
· The fracturing string is then pulled back and reoriented into the second lateral and strung into the liner for a pressure test.
· The fracture stimulation proceeds on Leg 2 as if it were an SL application.
· The fracturing string is then pulled out, the bridge plug in Leg 1 is retrieved, and the well is set up for production. Several optimization initiatives were introduced into the plan:
In areas of good reservoir quality, low-mesh sand was included in the scour.
Pumping rates were increased from 3.0 to 5.0 m3/min to improve cycle times.
The sand ramp was accelerated to a maximum of 1000 kg/ m3, which reduced fluid requirements.
A tracer study was conducted to provide evidence that the toe stage was contributing and that there were no obstructions in the lateral that were preventing inflow.
Reductions in the cost structure were realized with logistics planning on multiwell pads.
Seasonal efficiencies were captured by completing wells through the summer months to eliminate incremental heating costs.
Figs. 27 and 28 display costs normalized on a per-stage basis and completion fracture efficiencies displayed through the identified phases. A summary of some noteworthy observations is:
· Completion costs rose on a per-stage basis during the initial few DL multipad scenarios because of logistical items encountered (e.g., lease-equipment spacing, sourcing fluids and proppants to lease). Through applied learnings and intensified lease operations planning, these additional costs were eliminated. The average cost per stage during the time frame was reduced overall by 19%.
· Through continuous fracture-design optimization, fracture-treatment efficiencies continued to improve toward 99%.
· A cost savings of approximately 13% was realized from the OHMS SL design to the 2012 DL cost structure.
Six DL wells were drilled during the second half of 2011, with an average of 36 stages per well (Figs. 29 and 30). (Note: DL performance has been compared with 20-stage SLs at a similar stage spacing.) Some of the key observations are noted here:
· Initial production rates of the DLs demonstrate an approximately 1.85-fold improvement on inflow capacity when compared with SL wells with 20 stages (stage spacing of 55 m; 180 ft).
· After 6 months of production and before CGC application, cumulative recoveries of DLs were approximately 1.65-fold that of the recoveries in SLs with 20 stages.
· When normalizing the data on a production-rate per-stage basis, the productivity of DLs displays a very slight degradation of inflow (Figs. 31 and 32). This degradation is not unexpected because well spacing with the DLs was downspaced from 400 to 200 m (1,312 to 656 ft), effectively reducing the drainage area of each leg.
Through continual development and the deployment of technological advancements in industry, operators are now able to economically pursue tight-rock unconventional oil and gas resources. Through a methodical approach, the operator was able to reduce the risk of innovative technology deployment to ensure continual progression and enhancement of field-development economics.
Following a thorough evaluation of the 200 000 m (656,000 ft) drilled and 1,350 fracture stages pumped by the operator in the Slave Point, the following conclusions can be made:
· A methodical approach to field-development changes and deploying innovation in combination with steady program momentum with scale can aid in significant operational efficiencies, cost reduction, risk management, and economic benefit.
· Comparing the performance of OHMS to CL systems:
Inflow Capacity: OHMS systems have demonstrated superior inflow capacity. This can be attributed to the additional inflow provided by the openhole lateral, which remains available for production in OHMS-system applications.
Capital Structure: OHMS systems have demonstrated continually improving efficiencies in fracture treatment placement efficiencies and cost structure through time, mostly attributed to shorter completion times.
· Increasing the number of fractures per lateral was successful in generating increased inflow capacity. It is important to also note that economics needs to be considered because there is a tipping point of diminishing returns.
· DLs have provided a significant step change in program risk management, cycle times, and economics. They ultimately allow operators to improve the economics of unconventional resource programs and to transform poorer-quality resources into economically viable opportunities.
The authors would like to thank the management of Penn West and Packers Plus Energy Services for their permission to publish this paper. The authors would also like to thank Maria Meijer and Dan Penton at Packers Plus Energy Services for their assistance in the preparation of this manuscript.
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