tsp: s
`International
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`fi.1
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`SPE 164009
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`Open Hole Multi-Stage Completion System in Unconventional Plays:
`Efficiency, Effectiveness and Economics.
`Alberto Casero, Hammad Adefashe, Kevin Phelan, BP America Inc.
`
`COD'ftlghl2U13, Society of Petroleum Engineers
`This paper was prepared for Fll'ESE[IL!llI)rI at the SPE Middle East Unmnventiorial Gas Conference and Exhibition held in Muscat, Oman, 28-31] January 2013.
`
`This paper was selected for presentation by an SPE program committee lollowing review ufinlorrnation contained in an abstract submitted by the authorts] Contents oflhe paper have not been
`reviewed by the Society of Petroleum Engineers and are subyect to correction by the Et.lfhCtt{S] The rnetenat does not necessarily reflect any position olthe Society citPetruleum Engineers, its
`othoers. or members. Electronic reproduction, distribution, or storage ofany part at this paper wittioi.it the written consent of the Society otPetroleum Engineers is prohibited Ferrnisaon to
`reproduce in prim is restriiwed to an abstract of not more than GOD words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.
`
`Abstract
`During the past decade, the combination of hydraulic fracturing and horizontal wells, has proven to be the key, to the
`unlocking of unconventional plays across North America and elsewhere. This efficiency has been accomplished by rising
`two very distinct completion approaches: the Plug and Pcrf. method and the Open Hole Multi Stage (OHMS) completion
`system (typically ball activated fracturing ports).
`The OHMS completion system has in general been applied to carefully selected fields and ltas not yet gained wider
`acceptance, across the industry, as a viable alternative to the more popular and extensively utilised Plug and Perf approach.
`This resistance to change and the reluctance to consider alternative completion approaches, are due to a number of factors,
`many of which reflect an operational comfort zone from which there is a hcsitaney to stray. Often the disadvantages of the
`OHMS approach may be ovcrcmphasizcd, while the associated advantages are not suitably considered and vice vcrsa for the
`Plug and Pcrf approach.
`Case histories fi‘om a number of North American unconventional plays, for example the Red Oak, the Cotton Valley and
`the Granite Wash, will be both presented and analyzed. This analysis will focus on a number of aspects, including the
`hydraulic fracturing treatments, the operational efficiencies, the cost effectiveness and the overall risk reduction aspects of
`the OHMS vs. the Plug and Perf approaches.
`
`Introduction
`Over the past decade, the Oil and Gas industry has considerably increased the well completion activity levels taking place
`across the unconventional plays within North America. Continued advancements in both the completions technologies and
`the operational
`techniques, particularly when combining horizontal drilling and hydraulic fracturing, have allowed an
`ctlicicnt access to previously uneconomic resources to be achieved. These previously uneconomic resources comprise of a
`number of different plays, consisting of various pore fluids, formation lithologies and hydrocarbon trapping mechanisms.
`In
`this respect, the tight gas-sands, coal bod methane (CBM), shale gas and more recently shale oil opportunities can all be
`considered a part of the unconventional resource grouping.
`Fundamentally, the reasoning behind the consideration of horizontal well drilling is fairly simple, horizontal wells will
`provide an additional amount of contact area within the reservoir and by this means an improved production rate compared to
`a vertical well can be achieved. However, the reality is not as straiglttfonvard and the increased surface area, exposed to the
`reservoir, is not the only factor directly affecting this enhanced production rate.
`In order to explain more clearly, consider the simple derivation of the Darcy [low equation for an ideal liquid, for a
`vertical well (1), written in oilfield units. This equation simply states that the production rate (q) is directly proportional to
`the applied drawdown (op), the reservoir thickness (h), the formation permeability (k), the wctlbore radius (r,,) and is also
`inversely proportional to the pore-fluid viscosity (ti) and the fluid formation volume factor (B).
`
`A];
`kit
`was ...(1)
`l4l_2B;1 In LI"W
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`SPE 164009
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`In this form (1), Darcy’s law, for an ideal liquid, is based upon a number of very simple but important assumptions:
`
`that this takes place within a porous media,
`is a vertical well behaviour
`
`represents a radial flow regime
`consists of steady-state flow
`reflects a single phase
`has a homogeneous and isotropic permeability
`and has no partial penetration effects (open-hole).
`
`Numerous versions of this equation, describing various reservoir conditions, particular boundary effects and addressing
`sotne of the assumptions listed above; are widely utilised in the oil-field and are tnore generally known and referred to as the
`Inflow Performance Relationship (IPR) for a well. With the introduction of the dimensionless effective wellbore radius
`concept (Prats, 196! ), equation (1) was made applicable to hydraulically fractured vertical wells.
`However, regardless of what assumption is addressed in an IPR derivation (e.g. fluid compressibility, flow-regime, partial
`penetration, formation damage, etc.), a number of the most basic assumptions, primarily the vertical well behaviour and
`permeability isotropy, remain embedded within the IPR and therefore a different analytical solution is necessary in order to
`adequately represent horizontal wells.
`Horizontal well deliverability was first formulated by (Giger, 1984) expanded upon by (Joshi, I988) and further enhanced
`by (Economides, 1991). This equation introduces the horizontal well length (L); the elliptical shape of the drainage area
`described by the large half axis of such ellipse (a) as a fimction of L and permeability anisotropy (lam) as the square root of
`the horizontal to vertical permeability (1,, = (kHrt<,..-)"" ).
`Under steady state conditions and in oilfield units, the equation is (Economidcs, 1991):
`
`Q’ =] (2)
`[G + a2 —
`J
`{ant}?
`Ianfh
`1/
`+ I
`In Zr
`
`,
`
`,.
`
`l41.2B,u ln
`
`2
`
`This equation clearly demonstrates the potential influence of the vertical permeability on the behaviour of a horizontal
`well productivity-rate.
`In addition, the equation also indicates that
`the simplistic consideration of assuming that any
`additionally created wellborc-to-reservoir contact will result in enhanced performance, could lead to very disappointing
`performance due to the anisotropy effects.
`Nevertheless, the fundamental concept that any additional surface area exposed to the reservoir from a horizontal well
`will result in enhanced productivity is indeed correct; as long as the necessary steps are taken to address such issues as
`potential permeability anisotropy. Since 1947, hydraulic fracturing has provided a relatively eilicient way to increase the
`surface area exposed to the production (Vincent, 2009) and (Soliman, 2012), but more importantly (in this particular case) to
`eliminate such penneability anisotropy effects from the reservoir behaviour. Fu11he1'm0rc,the additional surface area created
`by even a small hydraulic fracture treatment is considerably larger than any other technique that the industry currently
`employs (e.g. slantedfhorizontal wells, multi-laterals, acid stimulations, larger well radii, etc.) and this has made hydraulic
`fracturing the most successful and most widely used stimulation technique of choice.
`The combination of hydraulic fracturing, with horizontal wells, has allowed a further increase in the surface area exposed
`to the production but with the addition of an extensive lateral aspect.
`In addition, the removal of the penneability anisotropy
`effect has effectively created a highly efficient three-dimensional resewoir drainage volume.
`In this way the application of
`hydraulically fractured horizontal wells, in unconventional plays, has enabled the industry to widely develop what were once
`considered uneconomic resources.
`
`In order to deploy this solution, the industry has developed numerous methods and techniques to efficiently execute such
`multiple hydraulic fractures in horizontal wells. Two of the most commonplace and widely used techniques are the Plug and
`Perf method (P&P) and the Open Hole Multi-Stage (OHMS) completion approaches. Although both of these techniques
`share the same ultimate goal they differ significantly from a completion, exeeutional and operational stand point.
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`Plug and Perf (P&P)
`Over the years this technique has become the most commonly applied and widely accepted approach across the industry,
`particularly with respect to unconventional plays. The typical P&P method and operational sequence consists of:
`
`Run production casing or liner into the well and cement the casing in place
`Open the first set of perforations - typically tubing conveyed guns, abrasive jetting or a ‘toe-sub’.
`Plug and Perf cycle:
`0 Acid is pumped ahead of the stimulation to clean up and break down the perforations.
`0
`Pump the hydraulic fracture treatment.
`0
`Isolate the stage with a frac plug — Qleployed with wire-line (pumped down in the horizontal section).
`0
`Perforatc the next stage - typically via pump down guns deployed in tandem with the frac plug.
`0 Repeat the Plug & Perf cycle until all of the frac stages have been pumped.
`- Mill out the composite plugs and llow-back the well.
`
`Pllug and Perl? teen
`
`Figure 1. Example of Plug 8. Perl Completion System Deployment Sequence.
`
`in an
`The number of hydraulic fractures required to achieve economic production rates when completing a well,
`unconventional play, can be significant (50 to 100 or even more). This creates a challenge regarding the practicality of
`applying the P&P methodology, having to separately plug, perforate and pump each single fracture stage would be
`uneconomic and time-consuming. Therefore, in order to address this, the industry generally adopted the perforation cluster
`approach, whereby the grouping of a number of perforated intervals (i.e. into perforation clusters) in the same pumping stage
`and simultaneously treating them reduces the overall effective stage-count. However, there are significant costs associated
`with numerous wire-line runs, perforating charges, plug setting and Inilling; the process can be time consuming especially as
`the industry trends towards more stages per well. Furthermore, there are additional safety and operational considerations that
`are associated with perforating and plug milling.
`Each frac stage is perforated with a number of perforation clusters, the geometry of such clusters will vary from play to
`play, operator to operator and much experimentationfvariation will take place to detennine appropriate selection criteria for a
`particular well/area. Typical ranges include the following, the number of perforation clusters may vary from 4 to 6 per stage,
`each cluster may be 1 or 2 ft long, with the clusters being spaced 50 - 75 ft apart. The intention of these clusters is that they
`are treated simultaneously, by diverting at high-rate while fracturing. The most commonly used method to implement
`diversion in P&P is the limited entry perforation technique. This consists of a combination of reducing the number of
`perforations and increasing the pump rate, such that the pressure drop itself across the perforations will help to uniformly
`distribute the flow to the entire set of clusters.
`
`The pump down technique is typically used to move the plug and guns along the horizontal section; and this approach
`requires that each of the frac-stages is consistently over-displaced. This over-displacement takes place at two distinct points
`during the P&P sequence. The first of these is at the end of the treatment itself, in order to obtain a clean wellborc and
`prevent any issue in subsequently running in the hole with the plug and guns the final proppant stage is swept and over-
`displaced from the wellbore. Secondly while running in hole with the wire-line deployed plug and guns themselves, in order
`to push them along the horizontal section and into the correct position for firing. These over—disp1acement phases may
`consist of several hundred barrels of fluid.
`
`Cluster efficiency has always been a key concern, despite the use of the limited entry technique, it is well known and
`there is significant evidence that not all the clusters are uniformly treated (from Radio-Active (RA) tracers and micro-seismic
`data) and/or do not equally contribute to the production (from Production Logging tools (PLT) and chemical tracers).
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`Open Hole Multi-Stage System (OHMS)
`With the objectives of making multi stage horizontal well fracturing more efficient, both in terms of cost and time, the first
`commercial OHMS systems were developed and deployed in 2001 (Snyder 2011). Since this introduction, the OHMS
`approach has been successfully applied on thousands of occasions (Rivenbark, 2011) around the World, in several different
`types of reservoir, including offshore applications (Casero, 2009 and Pace, 2008) and for recompletions (Casero, 2008). The
`OHMS approach consists of the following operational steps:
`
`Run production casing or liner and the OHMS assembly into the well
`Open the first frae port (typically pressure activated sleeve).
`- Multi-stage continuous pumping cycle:
`0
`Pump the hydraulic Fracture treatment
`0 At the end of proppant laden stages, drop the next frae port activation ball
`0 Displace, land ball and shift sleeve opening the next frae port
`0 Repeat until the multi-stage continuous pumping cycle is complete
`Flow-back well (mill out the seats if required).
`
`I
`
`©[@@rm IHl@fl@ tMlu1l~’tfi=-Sitae (©l%flMS))
`
`Figure 2. Example of OH MS Completion System.
`
`Currently, there are a number of commercial OHMS systems to choose from, but for the most part, these systems utilise
`similar principles. An OHMS lower completion assembly is deployed via drill pipe, and typically consists of a sequence of
`ball activated sliding sleeves, also called frae ports or more simply ports combined with open hole packers; which have been
`spaced out with production casing or production liner. The production liner remains uncemcnted, with the packers providing
`the annular isolation instead of the cement, hence the open-hole nomenclature. There are numerous variants of packers
`(mechanical, swellables, cups, etc.) that can provide the necessary inter-frac zonal isolation and these can be designed to
`withstand differential pressures as high as 10,000 psi (Houston, 2010; Lohoefer, 2006 and 2012; Samuelson, 2008).
`Each of the frac ports is individually activated by dropping a specifically sized ball into the system. The ball is pumped
`down the wellbore as part of the flush of the final stage and will seat on a tailored seat-size causing a sleeve to be
`hydraulically shifted and thereby opening the frac port. Once the ball has landed on its bespoke seat, the ball acts as a plug
`and creates internal isolation between stages, eliminating the need for frae plugs to be deployed. The system is also designed
`such that the balls will easily lift off the seal and allow cleanup of all of the zones simultaneously — this can be performed
`directly after the last stage has been pumped, thus minimizing the time that fracturing fluid is sitting on the formation and
`thereby potentially reducing damage. If the [low rates are sufliciently high the balls will be recovered on surface in an in—line
`ball catcher (Samuelson 2008; Snyder 2012).
`In order to avoid having ball fragments being produced over time and potentially interfering with surface production
`equipment, sometimes a Coiled Tubing (CT) milling operation is performed in the well. More recently an alternate practice
`is to use newly designed activation balls; such balls are made of composite nano-material containing magnesium, aluminium
`and other alloys, and decayfdissolve overtime once the operations have been completed (Carrejo 2012; Xu, 201 1).
`Although this system has been conceived primarily for open hole applications in new wells, there have been several
`applications in cased hole as an inner string for re-completion (Casero 2008; Pace 2008). In this case, the above operational
`sequence is slightly different and the casing may be additionally perforated before running in hole with the inner string used
`to convey the OHMS assembly.
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`OHMS and P8P comparison
`The P&P teclmique is the more widely utilised approach; this likely reflects a rel11cta11ce to tnove from an historically
`established comfort zo11e to an unknown lower completion approach. The P&P approach was the initial lower completion
`methodology that allowed the effective deployment of multi-fracture treatments in horizontal wells and it
`is difficult to
`progress from an established, standardized and successful technique; unless there are significant tangible benefits that can be
`demonstrated via a different method.
`
`Some of the features of the OHMS approach are often depicted as disadvantages, such as the in fcrrccl inability to control
`the initiation point of the fractures, the question of the reliabiiity of the open hole packer in providing zonal isolation, the
`perceived higher chances of mechanical failure and inability of opening the frae port, the complexity of the operation, the
`high cost of the down-hole jewellery (packers and frac ports mainly) and so forth. A detailed consideration of the features of
`the two approaches should ensure a fair and balanced comparison of the relative merits of the OHMS alongside the P&P
`approach; and in this way ensure the selection of the most appropriate technique on a case by case basis.
`Advantages and disadvantages of both systems can be considered systematically. The table below demonstrates a number
`of the major discussion points of the two methods, when directly compared. This table is not exhaustive and does not include
`all of the advantages and disadvantages that are contntonplace to the two approaches; items as noted in parentheses are the
`ones that are perceived to be more controversial.
`
`Plug and Perf Method
`
`Advantages
`
`Mature System and Technology
`
`Disadvantages
`
`Explosives Handling
`
`Control location of Fracutre Initiation
`
`Wireline/CT Deployment (Plug and Guns)
`
`{Flexibility in Case of Screen-Out)
`
`Near Wellbore Tortuosityf Perforation Friction
`
`Large Number of Stages
`
`Over Displacement: Frac and pump Down
`
`Mill out Plugs
`
`Longer Completion Time
`
`More Equipment/Se rvices and People on Location
`
`(Cluster Efficiency)
`
`Open Hole Multi Stage System
`
`Advantages
`
`No Ce me nting Operation
`
`No Wirel ine/CT Operation
`
`No Explosives Handling
`
`Disadvantages
`
`Additional Casing String/Trip Requirements
`
`Additional Cost of Dowhole Tools: Pake rs and Sleeves
`
`(Reduced Control of Fracture Initiation)
`
`Continuous Pumping Capability
`
`(Higher Proppant Flowback Tendency)
`
`Lower Fracture Initiation Pressure
`
`(Limitation in Case of Screen-Out)
`
`Less Frac Fluid Required
`
`(Reduced Overdisplacementl
`
`Shorter Completion Time
`
`Fewer Equipment/Services and People on Location
`
`(Drill out Opeation not always required)
`
`(Re-frac Operations may be possible)
`
`Permanent Reservoir Monitoring
`
`Limited Number of Stages
`
`(overdisplacement: Frac)
`
`Table 1. Comparison of Advantages and Disadvantages of P8P and OHNIS.
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`P&P Considerations
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`SPE 164009
`
`P&P can certainly be considered a mature approach, well proven in the field, for several years and within thousands of wells,
`the technique has been applied in every kind of unconventional reservoir including vertical wells where it is more commonly
`associated with the use of sand plugs rather than frac plugs. This gives the P&P approach an advantage when selecting the
`methodologies to be applied in the development of a new field, due to familiarity and comfort with the system at all levels,
`resulting in improved process efficiency with reduced non-productive times.
`P&P requires that a wider range of services and equipment (pumping, wire—line and potentially CT) be used almost
`simultaneously on location, larger locations may be required and more logistical effort in order to coordinate the operations
`which can result in higher associated overhead and underlying costs. Along with the pumping services, the P&P method
`involves the handling of explosives, required for perforating, with all of the associated HSSE aspects and increased costs.
`The first stage is typically accessed with abrasive jetting or guns conveyed with CT, although the introduction of a wet shoe
`or a toe-sub can eliminate this CT run, wire-line or CT is then required to deploy plugs and guns in all the subsequent stages.
`These operations take several hours per stage, depending on the depth of the well, and they require that the wellbore is
`clean or “sand-free", in order to avoid potential issues in running in hole with wire-line, hence it is also common practice to
`over—displace every frac stage by several barrels to flush all of the sand into the formation. Treatment over-displacement
`practice has been a concern to many operators and there are ongoing efforts within the industry to minimize this as much as
`possible. However, with this technique a significant amount of fluid is also used to pump down the plug and guns in the
`horizontal section of the well; which results in additional over-displacement since it is usually performed long before the
`fracture closure has been achieved.
`
`Finally a milling operation is required to remove the frac plugs; and typically CT or jointed pipe, are used for this
`operation. This milling requirement prevents the well from being flowed back immediately alter the fraes which may cause
`additional concern about creating damage to the fracture and further reduce cluster efficiency. Due to this operational
`sequence, P&P usually results in a longer completion time when compared to OHMS.
`
`OHMS Considerations
`
`OHMS was introduced approximately a decade ago and since then has been slow in gaining wider acceptance, even though it
`is a successfully applied completion methodology for multi fractured horizontal wells. The system, contrary to the P&P,
`does not have a unique industry accepted name and the authors have chosen Open Hole Multi-Stage or OHMS as this best
`describes the most common application (open-hole) and the fact that is typically applied to perform multiple treatments.
`Other nomenclature within industry literature refers to the approach as Continuous Pumping Multi-Stage System (CPMSS)
`(Casero, 2008) highlighting the fact that the system allows for continuous pumping operations or Ball Activated Sliding
`Sleeve (BASS) technique (Solin1an, 2012), because of the mechanism which is used to open the frac ports. Another simple
`option would be Packer and Port to mimic the style of Plug and Perf. Whichever name is utilised, the most important aspect
`is to understand that the OHMS approach is extremely flexible and adaptable to a number of applications.
`In this typical and
`The OHMS system, when applied in open hole, is an integral part of the production liner (or casing).
`most commonly used configuration no cementing operation on the production easing/liner is required; although there may be
`a requirement for a previous casing in order to provide adequate zonal isolation. Furthermore, removal of cement does not
`necessarily refleet a true cost saving, since the additional cost of down-hole tools (packers and frac ports) can easily exceed
`the cost of the cementing operation and the potential rig time saving can easily be absorbed by the longer time required to
`assemble and run the OHMS into the hole. Moreover, a reamer run is often required, as advisable good practice, before
`running in hole with the OHMS.
`One of the most important operational advantages, of this completion method, is that no wire—line or CT operations are
`typically required. The first sleeve is hydraulically actuated (by pressure cycling) and all the subsequent frac ports are
`activated by dropping specially manufactured balls during pumping, that shift sleeves, and as a direct consequence fewer
`equipmentfservices and personnel are required on the location. This approach also results in another two distinct advantages,
`continuous pumping operations and the use of less fracturing fluid. The frac ports are activated by progressively increasing
`the diameter of the ball that is dropped at the end of the sand laden stage during displacement of the treatment. Each
`activating ball is droppedfpumped into the fluid stream, a rate slowdown is required only to land the ball on the associated
`sized-seat, once the sleeve has shifted and the frac port is open the rate can be brought up immediately to break down the
`formation and perform the next fracture treatment. As the ball is injected into the fluid stream, this allows each treatment
`displacement (i.e. the wellbore volume) to be utilised as part of the pad, for the successive stage. Furthermore, there is no
`need for the fluid volume usually associated with the Plug and Perf to clean the horiyontal from sand and to pump down the
`plug and gtnis, resulting in less cumulative frac fluid required and a limited amount of over-displacement. Continuous
`pumping, depending on the frac design and number of stages, leads to execution of all of the pumping operations in few days;
`pumping I2 or more frac stages per day is perfectly achievable with this method against the average of 4-6 stages with the
`P&P technique.
`Having the open hole directly exposed to the fracture pressure can eliminate additional pressure drop generated by the
`perforations and perforation tunnels; as well as minimizing fracture tortuosity, this method will allow the fracture to easily
`take the path of least resistance along the open hole section exposed, resulting in a lower fracture initiation pressure. The
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`downside of this approach can be less control on the location of the fracture initiation. However, opportunity exists to reduce
`the packer spacing in order to achieve a more defined initiation point (Casero, 2009).
`In addition, new frac port designs,
`which allow having multiple ports open with the same diameter ball (mimicking the multiple cluster approach with P&P), are
`now appearing on the market.
`Milling operations are not typically required with this system for general application, however the practice of milling out
`the balls and seats is sometimes adopted because it is not always possible to flow all the balls back iirunediately. When the
`balls remain in the wellbore, they can stiffer degradation and break down to smaller pieces due to pressure, temperature and
`reservoir fluid exposure; these balls fragment are then potentially produced back and can cause damage to production
`equipment or impair production, More recently, disappearing balls, made of composite nano-material have been introduced
`to the industry with the primary aim of avoiding milling operations.
`The OHMS system can also be used in eased hole as an inner string, when tubular dimensions permit, and this has made
`the system a good choice for remedial or re-fracturing operations. Not requiring perforations to be ‘shot’ in the casing has
`also made this system a candidate of choice for permanent reservoir monitoring technology such as fibre optic(s).
`
`OHMS vs. P&P completion sequence
`Another approach to comparing the two methodologies is by focusing on the different phases of the completion sequence:
`
`Table 2. Comparison of Operational Sequence of P&P and OHMS.
`
`Horizontal Multi-Stage Hydraulic Fracturing Sequence
`
`Prepare Hole/Set Casing Top Reservoir
`
`2
`
`
`
`Run production liner/casing
`
`Cement production liner/casing
`Open first stage (TCP or abrasive jet)
`
`Pump first frac treatment
`
`Overdisplace to have a clean wellbore
`
`WL run to deploy plug and perforate
`
`Pump down WL in horizontal section
`
`Pump subsequent fracls}
`
`Mill plugs
`Mill ball seats
`
`Run production tubing
`Flowback well
`
`The completion sequence ca11 be split into four distinct phases: (1) Pre-frac phase, consisting of landingfplacing the lower
`completion and preparing for the first stage; (2) Hydraulic fracturing phase, this is the core of the completion sequence and
`consist, as the name says, in the pumping of all the fracturing treatments planned for the well but includes sequencing from
`one stage to the next; (3) Post-frac phase during which all the plugs (or the balls) are milled out and the production tubing is
`run in the hole; and finally the (4) Clean up phase when the well is flowed back and handed over to production. Note that in
`a number of cases that the tubing is run long after the clean up and the well is flowed through the casing for quite some time.
`Depending upon which of the two systems is utilised, the first three phases can differ quite substantially in terms of their
`cost, complexity and duration. A general cost analysis may not be possible since the costs involved can be dependent upon
`contractual strategy and company structural organization. As an example a vertically integrated company, owning drilling
`rigs, frac units and perhaps sand mines, may not find additional saving(s) coming from continuous pumping to be attractive
`and may prefer to stay with the more established P&P approach. Familiarity with the approach can deliver efficiencies
`through expertise rather than the potential savings derived from a more time efficient system, such as the OHMS, but which
`is perceived to introduce a certain degree of unreliability and complexity.
`[11 any case, it is quite evident from the Table
`above and from the previous discussion,
`that
`the hydraulic fracturing phase, if associated with OHMS, can be greatly
`improved in terms of the cost and duration.
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`SPE 164009
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`Field Example #1: Red Oak.
`
`Geology and Reservoir Description
`The middle Atoka (Lower Pennsylvanian formation) Red Oak tight gas field is located in Oklahoma and is an integral part of
`the Arkoma basin. The Red Oak sandstone is characterized by a complex sedimentary depositional environment with
`inclined bedding set and scour surfaces (Churnning, 2009). The Red Oak sandstone is characterized by formation porosity,
`varying from 3% to 10%, but with a permeability of just a few micro Darcies, the gross pay thickness is 100 - 180 It with a
`potential net pay of 80 it to 150 Itwhich is typically encountered at about 7,500 ft.TVD. The sandstone is inter-bedded with
`shale stringers, is very sensitive to fresh water, with considerable risk of fines migration causing formation damage and
`fracture conductivity impairment. Laboratory testing has demonstrated the use of potassium chloride brines only marginally
`mitigates this problem and the shale remains unstable, fresh water was used as the base fiacturing fluid for testing.
`
`Top Bounding Shale
`
`Stalclnrngen
`Flacsameliol
`Pnelillflmian hFIa-It
`
`Bottom Bounding Shale
`
`Fra::ul'Frac Ports
`
`Figure 3. Red Oak Gross Pay Schematic.
`
`Figure 4. Shale, Fresh Water and 9 ppg KCI Brine.
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`Well and Completions Design
`The lower completion approach chosen for these wells was the OHMS, with lateral length of 1,700 to 3,300 ft and fiac port
`spacing of 400 -500 it based on the low penneability resulting in 5 to 8 stages per well (see Fig. 5). Frac ports were placed in
`the clean sand portion of the well, while shalier sections were packed off aiming to obtain a better fracture initiation point and
`limiting the opportunity to contact the interbedded shales. Seine trials have been performed on packer placement, associated
`with micro seismic results, in order to better understand the created fracture geometry and propagation. Micro-scismicity has
`demonstrated (see Fig. 6) that fractures initiating from ports, isolated by packers, have less complexity and do not overlap
`with previous stages (stages 4, S and 6 in the example below). Conversely, when the isolation packer is absent (stages 1 and
`2 in the example below), or when differential depletion is present along the lateral, much more fracture complexity is created
`along with an extensive fracture overlap.
`
`
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`Figure 5. Example of Red Oak OIIMS Completion.
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`Figure 6. Microseismic Events W! and wife Packers.
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`The hydraulic fracture designs, consisted of cross-linked gel fracs pumped at 40 - 60 bpm with proppant concentrations of up
`to 7 ppg. Proppant utilised was 20!-4