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`SPE 112442
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`Continuous Pumping, Multistage, Hydraulic Fracturing in Kitina Field,
`Offshore Congo, West Africa
`Alberto Casero, SPE, and Giamberardino Pace, SPE, Eni E&P; Brad Malone, SPE, and Francois Cantaloube,
`SPE, Schlumberger; Loris Tealdi, SPE, and Henri Malonga, SPE, Eni Congo; and Rocky Seale, SPE,
`Packers Plus Energy Services
`
`Copyright 2008, Society of Petroleum Engineers
`
`This paper was prepared for presentation at the 2008 SPE International Symposium and Exhibition on Formation Damage Control held in Lafayette, Louisiana, U.S.A., 13–15 February 2008.
`
`This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been
`reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its
`officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to
`reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.
`
`
`Abstract
`Many West Africa offshore fields are maturing and operators are completing secondary targets in their wells to maintain the
`economic operation of their valuable assets. Large quantities of reserves can be found in low permeability, consolidated,
`formations and new techniques are being investigated to improve the economic return of completing these formations.
`
`The Kitina Field, offshore from Pointe Noire, Congo, is one such field. Deeper sands have been produced to economic
`depletion and the operator is looking for alternative production intervals.
`
`The targeted reservoir is the 3A Sand at approximately 2200 meters TVD. The reservoir is a very heterogeneous lithology
`with varying quantities of siltstone, sandstone and calcite. The intervals of better porosity show a decrease in clay content,
`but the good “sands” can be either dominated by quartz or calcite with substantial variations with each meter of height.
`
`Three candidate wells were selected for placing multiple propped fractures using a technique that has been used for six years
`in North America. This technique utilizes a series of mechanical packers and frac ports that are sequentially shifted “on the
`fly” allowing continuous placement of more than one hydraulic propped fracture without shutting down the pumping
`equipment.
`
`During April to June of 2007, eight hydraulic propped fractures were placed in three re-completed, cased-hole wells in the
`Kitina Field with very encouraging production increases. During the first 90 days of post fracturing production, a production
`increase of 200% was achieved.
`
`This paper will discuss the steps that were taken to place these propped fractures from an ocean going tender barge using skid
`equipment and recommendations for the future applications of this stimulation technique.
`
`Introduction
`The Kitina Marine offshore field was discovered in 1991 and put on production in November 1997. Originally, the field
`development considered the three deeper intervals:
`•
`2A – Limestone,
`•
`1A – Sand with carbonate cementing,
`•
`1B – Limestone.
`
`
`The three reservoirs were developed via a peripheral water injection scheme and a crestal gas injection displacement process.
`After a quite significant initial rate (around 50,000 BOPD), the field declined quite rapidly. The recovery factors vary
`between 15% of the 1B reservoir to aroud 25-30% of the 1A and 2A reservoirs.
`The platform has gas lift installed on some of the completions and others produce in natural flow. Production of the platform
`was 7,000 BOPD prior to the fracture stimulation.
`
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`IWS EXHIBIT 1053
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`The 3A Sandstone reservoir was initially completed in natural depletion between the end of 2005 and august 2006 via the
`recompletion of three deeper wells into this shallower and low permeability reservoir (gas lifted wells). The formation
`permeability to oil is in the range of 2-7 mD. Due to the low permeabilities, during the first year of production, the reservoir
`3A oil production potential has been of around 800 BOPD. Their steady-state production was:
`
`
`• KTM W6 ST – 160 BOPD
`• KTM 107 – 130 BOPD
`• KTM 111 – 300 BOPD
`
`
`Level 3A in Kitina field had progressively declining production heading to a marginal-economic scenario. A study was
`carried out by Eni Congo and Eni E&P with the final objective of re-establishing the reservoir 3A production to a viable
`economic level (more than 1500 BOPD) without drilling new wells or performing heavy workover operations. Because of the
`low rates of the three wells producing from the 3A Sand, this target could have been achieved only with a massive hydraulic
`fracturing operation on all the wells. Therefore the three wells were selected to be treated. Secondly, this was considered an
`attractive situation for testing new technologies and techniques to build a learning curve applicable in other similar situations
`opening a wide scenario for further applications in other low permeability reservoir of the Congo Basin. For this reason,
`different technologies were evaluated and eventually the Continuous Pumping Multi-Stage System (CPMSS) technique was
`selected.
`
`The CPMSS allows pumping multiple hydraulic fracturing treatments without the need of intermediate operation such as
`bridge plugs or proppant plugs (run in hole, set, retrieve, and mill or clean) and perforate each interval with multiple TCP or
`wire-line operations. The CPMSS hardware is a permanent bottomhole assembly that is run and set into the hole after all the
`interval requiring fracturing treatment has been perforated. This peculiarity allows the placement in the formation of multiple
`treatments with a continuous pumping operation; the limiting factor is represented by the amount of proppant that can be
`stored in the silos (or equivalent storage system) and the amount of fluid available.
`
`In conclusion it is possible to pump all the treatments planned in each well in just a few hours which is a substantial time
`savings. This has the potential to become a remarkable advantage in offshore operation with the rig on location.
`
`Offshore Fracturing Challenges
`The petroleum industry has made a well documented effort to improve the production of laminated pay intervals with the use
`of fracturing 2,8,9. The large volume of data provides significant support for hydraulic propped fracturing to improve the well
`deliverability from laminated pay intervals by improving the poor vertical communication due to negligible vertical
`permeability.
`
`The industry has also discussed, in much detail, the benefits of placing multiple fractures into a wellbore. These papers are
`usually discussing this application in horizontal wells where a single reservoir is drilled and stimulated multiple times from
`the same wellbore3,6,10.
`
`Hydraulic propped fracturing of consolidated formations is not new to West Africa reservoirs. During the early 1980’s,
`hydraulic fracture stimulations had been performed in Gabon from a dedicated stimulation vessel. Both gelled water and
`gelled oils were used to place sieved sand and man-made proppants into laminated sandstone intervals in a large field of
`similar characteristics of the Kitina Field in Congo4.
`
`In 1991, three prop fractures were performed with good economic success in the Takula Field of Cabinda, Angola1. A
`detailed paper was written to discuss the philosophy and methodology of fracturing low permeability, thick, heterogeneous,
`offshore intervals in the N’Dola Field of Cabinda in the 1998 time frame. The authors describe their methods for placing
`multiple fractures into a well lithology that is similar to many fields in West Africa from Gabon to Angola.
`
`The work in Cabinda has evolved into placing two or three hydraulic propped fractures into these slanted wellbores in the
`interest of connecting as much of the laminated pay as possible to the wellbore. A very large single fracture was not effective
`at growing through all the intervals of interest and then producing through bi-linear flow into a narrow contact area with the
`wellbore due the limited perforation interval required for fracture execution in deviated cased hole wells.
`
`In late 2006 and early 2007 it was decided by the operator and partners of the Kitina Field of Congo to investigate propped
`fracturing several selected candidates from their existing wells. These candidate wells were cased and perforated. Some of
`the wells that were considered as candidates had continuous perforations over the entire interval and others had individual
`sand bodies perforated with breaks between perforations.
`
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`A selected technique would have to isolate each interval and stimulate individual sands. One technique of interest that is
`being used in North America for vertical to horizontal wells also had the benefit of being a continuous pumping placement
`system 7,12. This type of tool application had been successfully used for the first time offshore during late 2006/early 2007 in
`neighboring Gabon, West Africa and it was decided to use this technique on a few selected candidates in the Kitina Field.
`
`Physical limitations of fracturing offshore
`There are many limitations to fracturing offshore that may not be an issue on land. The following is a partial list:
`• Space limitations
`• Weight/area restrictions
`• Flow back of hydrocarbons and solids
`• Sea conditions
`• Location / remoteness / access
`• Available marine and stimulation equipment resources
`• Mobilization expense for all rig and stimulation equipment
`• Crane availability of the dock and the rig/platform
`• High expense to re-mobilize to correct sanding issues
`A dedicated stimulation vessel with an experienced crew always looks very attractive and it would be expected to be the most
`efficient approach, but in times of high utilization of oilfield service equipment, these vessels are in very high demand and
`there is a risk that they may not be available when the completion calls for them. The very large area of West Africa
`stretches the capabilities of the existing vessels that are in the theater of operations to reach a rig in a timely fashion. A
`vessel sailing from Nigeria will take 2.5-3 days to reach this rig work in Congo (See Figure 1). Each country is its own
`sovereign nation as well, so time must be allotted for customs clearance upon arrival and for departure from each country
`visited.
`
`The required frac equipment to perform this work would take up too much space on most, if not all rigs and platforms of the
`industry, hence that is eliminated as an option. Placing skid equipment on the deck of a service vessel was evaluated and it is
`a relatively common practice5 that is occurring in many marine operation areas. Just as stimulation vessels are in high
`demand, so are service vessels. A large fracturing treatment would require a large service vessel of 600 m2 deck space or
`larger. Sub systems of the vessel are used for air transfer of proppant. Below deck pumps and tanks are used for mix water
`and mixed gel storage. Therefore, the selection of the vessel and the access for cleaning these tanks and lines would be
`critical.
`
`Figure 1 – Sailing time West Africa
`
`A days sailing
`
`Por - HarcouPor - Harcour
`
`t
`
`Malab
`Malabo
`
`Por - Gent
`Port - Gentil
`
`Point- Noir
`Pointe - Noire
`Cabin
`Cabind
`Soy
`Soyo
`
`
`
`LuandLuanda
`
`Another option that was considered and chosen to pursue was to
`place the skids on the deck area of the large platform tender rig
`support barge, the Barracuda. (Figure 2). The rig-up is
`comfortably placed on ~1200 m2 of open deck space. All the
`equipment on the single level of the deck was adequate to perform
`the stimulation treatments except the additional use of 1500 bbls
`(240 m3) of the tender pit systems located directly below the
`blender system that held additional quantities of pre-blended gel.
`
`The selection of the Barracuda (See Schematic 1 below) as the
`work platform and the use of skids then will put certain criteria in
`motion of the abilities and the limitations that control the
`execution of the fracture stimulation. A fracture design and
`sequence of operations must then be built around the given set of
`equipment, capabilities and available crew.
`
`The major reasons for selecting the skids on the floating barge
`were:
`• Captive pumping package that would be available as soon as
`the rig was ready for stimulation.
`• Up front costs of the skid equipment is lower than using a
`dedicated stimulation vessel.
`• The anchored and moored barge reduces risk of a weather interruption when pumping is initiated.
`• Unavailability of either a dedicated stimulation or service vessel.
`• Rig support barge was required to re-complete the well.
`
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`SPE 112442
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`Figure 2 – Frac Equipment on Barracuda Tender Barge
`
`This rig-up on the Barracuda gave us the capability of having
`access to 2,500 bbls (400 m3) of gelled fluid, 150,000 pounds of
`proppant in two gravity silos feeding the blender and another
`100,000 pounds pneumatically delivered (depending on timely
`transfer) to the gravity silo. 5,600 HHP of four fracturing skid
`pump were rigged up and available for these treatments planned
`to be pumped at 20-30 barrels per minute. A freshwater based,
`batch mixed fluid was utilized with this volume of fluid storage.
`
`Fracturing Application to Kitina Field
`There has been a search ongoing for decades to improve the
`efficiency of fracturing horizontal wells ever since it has been
`identified that horizontal well production can be improved by
`fracture stimulation 11,13. One of the last approaches that have
`been developed was to use a system that becomes a permanent
`completion liner. This system is a series of external, mechanical
`element packers that can be screwed to the deployed liner in
`stategic places for isolation. Between each of the packers is a
`sliding sleeve referred to as a frac port. The use of the packers
`allows the wellbore to be segmented into selected areas for
`stimulation. Packers of a specified size can be used in either
`cased hole to straddle perforations or in open hole wellbores to
`segment that type of completion.
`
`The method of selectively opening the frac port is to drop
`progressively larger diameter ceramic balls that land on a
`beveled seat below each of the ports. The seating ball allows
`sufficient pressure to be applied to create a down force that will
`shift the sleeve to the open position while isolating the previously placed fractures of the ports at deeper depths.
`
`There are several theoretical benefits of using this continuous pumping, multi-stage system. Many of these have been
`realized on land operations and our attempt was to carry these benefits to a marine well. Some of them are:
`• With adequate bulk capacity, all stimulation can be done in hours instead of weeks
`• Quicker fluid recovery due to the short time for the injection process
`• Reducing rig costs may encourage additional fracturing treatments for enhanced stimulation of the well
`• The sliding sleeves will allow interval isolation at a later date
`
`The technique has been previously applied for the first time on a marine well in Gabon, six months previously. The four
`wells were that fractured in Gabon, were three open-hole completions and one cased-hole completion.
`
`Fracturing Execution of Offshore Kitina Fractures
`Kitina Marine W6 ST
`The first candidate well was KTM W6 ST. This well has 7” 29 ppf L-80 cemented liner run from 1,600 – 3,110m. The well
`was a re-completion from a lower interval. The intervals of interest for fracturing were in the 3A Sandstone. These
`perforations had been placed on gas-lift production in August of 2006 until the time of the workover to fracture the
`perforations in April 2007.
`
`This well was perforated in three intervals from;
`• 2,785m – 2,810m, (2,099m – 2,111m TVD), 4.5” Guns, Big hole charges, 12 jspf, deviation 62.1o
`• 2,820m – 2,865m (2,115.3m – 2,135.3m TVD), 4.5” Guns, Big hole charges, 12 jspf, deviation 63.2o
`• 2,870m – 2,910m (2,145.4m – 2,157.6m TVD), 4.5” Guns, Big hole charges, 12 jspf, deviation 64.5o
`
`
`New perforations were added in 2 meter groups to each of the well perforation sets in the interested of reducing the risk of a
`screen-out caused by tortuosity, prior to running the packer assembly into the well.
`
`The packer assembly (Schematic 2) is run to depth to allow the packers to straddle the three perforated intervals. This
`assembly is run on 4-1/2” 12.75 ppf tubing as a production liner assembly. The setting tool is then pulled from the well and a
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`fracturing seal assembly is then run into the well and landed in the sealbore of the liner hanger packer. The tubing annulus
`was then isolated with the Blow Out Preventors (BOP) at the surface. During the fracturing treatment, annulus pressure was
`maintained by a rig pump and the pressure is monitored by both the rig crew and the fracturing control monitoring system. A
`4” master valve was placed on the frac work string as tubing isolation as well as valves in the treating equipment lines of the
`frac spread (Schematic 3).
`
`Schematic 3 – Wellhead Configuration
`
`When the production liner assembly is run and set, all the
`sleeves and access to the perforations are closed. The initial
`fracture port is opened with pressure differential. All
`remaining intervals are manipulated using a ball which also
`acts as isolation for any fractured intervals located below
`the targeted interval. After the initial frac port is opened
`hydraulically, each sequential port is opened with a ball
`sized specifically to a seat made for that particular ball size.
`
`Injection Test
`The initial steps of this fracturing operation were to pump
`several pre-frac injections for diagnostic purposes. The
`annulus pressure was increased to 1,000 psi and then the
`tubing pressure was increased until the hydraulic fracturing
`port was opened, exposing the lower most perforated
`interval. This fracture port opened at 4,500 psi surface
`pressure as designed.
`
`Rig
`Cement
`Unit
`
`Testing
`
`2"
`Check
`Valve
`
`WxW
`
`Pressure
`Relief
`Valve
`
`2"x2"
`
`13
`2"x2"
`
`Pressure
`Sensor
`
`#3
`
`4" Ball Dropper on
`manifold stand
`
`2" Tee
`
`12
`2"x2
`
`"
`
`MANIFOLD
`KILL LINE
`
`CHOKE
`
`2" Tee or with
`2 each 2x2
`9
`5
`
`2" x 2"
`
`3" 1502 Male (Wing)
`to Test Package
`
`5
`
`3" Tee x 2"
`port down
`4"
`coupling
`
`Needle
`Valve
`
`2"x1"2
`
`" 90
`bleed-
`off
`
`Xover
`4"x2"
`
`4"
`Gate
`Valve
`
`4" Ball
`Catcher
`
`4" Tee
`4" port
`
`4"
`valve
`
`4" Tee
`4" port
`
`4"x2"
`Xover
`
`4" Iron
`
`4"
`Hydraulic
`Master
`Valve
`
`4" 3-Way
`Chicksan
`
`OVERBOARD /
`SHAKERS
`
`4
`
`3" 2-Way
`Chicksan
`
`4" 2-Way
`Chicksan
`
`4" Pup
`Joint
`
`4" 2-Way
`Chicksan
`
`3" 2-Way
`Chicksan
`
`3" Master
`Valve
`
`4" 1002 Lateral
`x 3" 1502
`thread
`Cement Line
`
`Galaxie
`TIW Valve
`4-1/2 IF
`Pin
`
`X-Over 4-1/2"
`CS Hydril
`Tubing
`
`3" 2-Way
`Chicksan
`
`Cement Unit
`
`3" Master
`Valve
`
`X-Over 4"
`1002 Thread
`x 4-1/2 IF Pin
`
`3" 2-Way
`Chicksan
`
`3" 3-Way
`Chicksan
`
`3" 3-Way
`Chicksan
`
`Pressure
`Sensor
`
`3" CoFlex
`
`3" CoFlex
`
`CHOKE
`MANIFOLD
`CHOKE LINE
`
`Inner &
`Outer Gas
`Relief
`Valves
`
`Choke Isolation
`Valve
`
`Upper Inner &
`Outer Choke
`Valves
`
`Lower Inner &
`Outer Choke
`Valves
`
`Rig Pumps
`
`KILL LINE
`
`Kill Isolation
`Valve
`
`Upper Inner &
`Outer Kill
`Valves
`
`Lower Inner &
`Outer Kill
`Vlaves
`
` A
`
` Step Down injection test was then performed to evaluate
`the near wellbore perforation and tortuosity restrictions that
`may exist. Linear gel was pumped at rates from 25 bpm
`down to 12 bpm and then the shut-in pressure was
`monitored for 60 minutes.
`
`The formation breakdown pressure was observed at
`approximately 2000 psi on the surface. The total measured
`friction observed at 20bpm was 500 psi. 100 psi was
`allocated to the perforations and 265 psi was attributed to
`tortuosity.
`
`
`
`Calibration Test
`The next test performed was a 325 bbl injection of a 35 pound gel loading delayed borate crosslinked gel. This was pumped
`at 20 and 25 bpm. The pressure decline post shut-in was observed for 60 minutes.
`
`Frac Design
`Based on the pre-job Step Down Test and the Calibration Test the fracturing parameters were adjusted in the Pseudo three
`dimensional fracture models. A summary of each of the wells is listed in Table 1.
`
`Propped fracturing execution of frac ports 1 and 2 followed later by frac port 3
`The KTM W6 ST was the first well to be fracture stimulated on the Kitina platform on April 13, 2007. The stimulation liner
`assembly was run into the hole on 4-1/2” tubing and set across three perforated intervals. During the treatment of the bottom
`and middle zones were fractured stimulated without shutting down the pumps.
`
`100,756 lb of 20/40 Intermediate strength, light-weight, ceramic proppant (ISP) was placed in the lower-most interval and
`106,154 lb of 20/40 ISP was placed into the middle perforated interval. A frac ball was launched immediately upon starting
`the flush of the first fracture. This allowed the lower fracture to be isolated and opened the fracture port of the second
`interval. Figure 3 shows the responding data of these two fractures being placed.
`
`You will notice that two proppant slugs were pumped in the pad fluid of fracture number 1. A proppant slug was late in
`being delivered on fracture number 2. The pumping rate is consistent at 20 bpm until the rate is reduced to have a controlled
`launch of the frac ball on the surface and then again when the ball is calculated to land at the fracture port. The placement
`time of two discrete propped fractures was 123 minutes.
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`IWS EXHIBIT 1053
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`As explained earlier, the volume of the equipment on this rig-up required that the proppant silos and the gel had to be re-
`loaded after the initial two fractures. It had been planned to shut-down after the initial two fractures and then continue
`pumping after these preparations had been done. Unfortunately the top frac port was opened, but had received sand fill,
`causing the annular area to be filled with proppant, making it impossible to place the third fracture through the port.
`Perforations were shot through the stimulation liner and the third fracture (see Figure 4) was placed via these new
`perforations. A new step was added prior to shutting down on these multi-phase fractures, the port must be opened and the
`fracture initiated by pumping a non-proppant laden fluid into the open port prior to shutting down. This assures that the
`fracture port is open and ready to accept the next proppant stage.
`
`Kitina Marine 111
`The second candidate well was KTM 111 and this well had three intervals that were to be fractured. This well has tapered
`production casing of 10.75” 55.5 ppf L-80 and 9-5/8” 53.5 ppf L-80 string set at 2,496m and was perforated in one
`continuous interval:
`2,240m – 2,320m, (2,120m – 2,151m TVD), 7” Guns, Deep Penetrators charges, 8 jspf, deviation 24o
`
`The fracturing packers were placed in the perforations to break up the well bore into three intervals. No additional
`perforations were added in this completion that was shot with 8 jspf of Ultra Deep Penetrating perforations.
`
`The fracturing assembly was run on 4-1/2” 12.75 ppf tubing as a production liner assembly. The setting tool was then pulled
`out from the well and a fracturing seal assembly was then run into the well and landed in the 10 feet long seal bore of the
`liner hanger packer. The tubing annulus was then isolated with the Blow Out Preventers (BOP) at the surface. The
`fracturing procedure is similar to KTM W6 with the annulus pressure maintained by the rig pump and monitored with both
`the rig and the frac control unit.
`
`The Packers and frac ports on this well can be found on completion (See Schematic 4).
`
`Propped fracturing execution of frac ports 1 and 2 followed by frac port 3
`The procedure was similar on this well with a mini fall-off test followed by a step rate, a step down and calibration injection
`pumped prior to the first prop fracture. The volumes were slightly adjusted based on the initial data from the diagnostics
`testing.
`
`The fractures of the lower and middle intervals were pumped on May 17th 2007. 94,105 lb of 20/40 ISP was placed in the
`lower-most interval and 91,528 lb of 20/40 ISP was placed into the middle perforated interval. A frac ball was launched
`immediately upon starting the flush of the first fracture. This allowed the lower fracture to be isolated and opened the
`fracture port of the second interval. Figure 5 shows the responding data plots of these two fractures being placed. The
`second fracture was followed by a second, larger, frac ball that opened the port of the third frac and isolated both the intervals
`that were fractured below. This interval was overflushed with brine by 100 barrels to be sure the fracture port was open and
`clear to allow fracturing of that interval after the proppant and gelled fluids were prepared. This overflush acted also as an
`additional injection test on the upper level.
`
`The third fracture treatment was placed three days later with 178,802 pounds of 20-40 ISP placed into the fracture (See
`Figure 6). The treating and pressure plots of all three fractures are shown with post frac pressure matching performed to
`arrive at the post fracture interpretations of the fracture properties.
`
`The data as interpreted from the data pumping segment of the treatment in listed on Table 2.
`
`Kitina Marine 107
`The third candidate well was KTM 107 and this well also had three intervals but the lowermost perforations were close to an
`Oil Water Contact so it was decided that the lowermost perforations would have a packer above the lower perforations, the
`port opened, but the interval would not be fractured.
`
`This KTM 107 well was completed with a 7” 29 ppf, C-75 liner from 2,425m-3,032m. The 9-5/8” 53.5 ppf, L-80 casing
`extended down to 2,580m.
`
`This well was perforated in one continuous interval:
`2,454.5m – 2,565m, (2,143m – 2,151m TVD), 4-1/2” Guns, Ultra Deep Penetrators charges, 5 jspf, deviation 51.4o. Thus the
`fracture would have to be placed through both the 7” and the 9-5/8” casing strings that were cemented in place.
`
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`IWS EXHIBIT 1053
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`EX_1053_006
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`Downloaded from http://onepetro.org/SPEFD/proceedings-pdf/08FD/All-08FD/SPE-112442-MS/2742148/spe-112442-ms.pdf/1 by Robert Durham on 12 September 2023
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`SPE 112442
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`7
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`The isolation packers were placed in the perforated intervals at 2,515m to isolate the bottom perforations. Another packer
`was placed at 2,471m, which separated the upper perforations into two intervals. The production liner top packer was at
`2,434m, only 9 meters below the 7” liner top.
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`The fracturing assembly was similar on all the wells. The base pipe of the fracturing liner is a 4-1/2”, 12.75 ppf tubing
`placed between all the packers and the fracturing ports. The setting tool was used to place the assembly on bottom and then
`pulled from the well. A fracturing seal assembly was then run into the well and landed in the sealbore of the liner hanger
`packer. The tubing annulus was then isolated by closing the Blow Out Preventers (BOP) at the surface.
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`The Packers and frac ports on this well can be found on completion Schematic 5.
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`This procedure was different since the lower interval was to be opened for production, but not fractured. The lower most port
`was opened with hydraulic pressure and then an isolation ball was dropped and slowly pumped down to land in the seat and
`open the middle frac port. This was successfully accomplished and then a mini-frac was performed on the middle
`perforations of this well.
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`The data as interpreted from the data pumping segment of the treatment in listed on Table 3.
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`Propped fracturing execution of Frac Port 2
`The fracture of the middle intervals occurred on June 9, 2007 and was performed as expected and placed the designed 99,000
`pounds of ISP into the middle interval. The last minute of the displacement did not go as planned. See Figure 7.
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`As stated earlier, in an operation such using skids that do not have adequate volumes to pump multi-stage fracture treatments,
`a ball must be landed and the fracture port opened and overflushed to allow time for the re-stocking of proppant and gel. In
`this case when the ball landed, the fracture port opened, but the top fracture port sanded off within seconds of the ball landing
`on the port.
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`This could be caused by two mechanisms that were both possible in this well.
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`1. Proppant behind the fracturing ball would be the first placed into the new perforations before adequate pad would open a
`fracture.
`2. There was communication behind the casing, placing proppant into the “open” 7” x 4-1/2” annulus which would also
`block the perforations.
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`An evaluation of the procedure for dropping the frac ball was done and it was determined that the ball was dropped into the
`treating line when it was planned. Further investigation determined that it is a somewhat known, but obscure and not
`documented occurance the frac balls are subject to gravity, even when being pumped at high rates down fracture tubing. If a
`calculation of the force of gravity is performed on the ball, it is found that it could be possible for the 1.25 Specific Gravity
`ball could advance 4-6 bbls in the 1.03 SG fracturing fluid. Instead of the ball being behind several barrels of clean frac
`fluid, it is theorized that the ball would instead have 2-3 barrels of slurry behind the ball. When the ball lands and opens the
`frac port, a slurry of 8 ppa proppant in the first fluid to enter the annulus and cause a screen-out of the perforations.
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`This phenomena has not been a serious issue in North America as the spacing of the fracturing ports is normally 150 meters
`or more and more flush can be placed in front of the be fracturing ball before it is launched without over-flushing the
`previous propped fracture. The annulus area we were dealing with was also very small. It would take very little proppant to
`cause an issue in an annulus with only 2.2 bbls of annular area in this cased hole.
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`The other possible explanation for the screen-out was also possible as it was determined the quality of the cement bond in the
`very top of the 7” liner top was somewhat suspect. It was possible that there was communication around the single packer
`that was set in the perforations.
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`An indication that significant proppant had been placed into the annulus, more than would have been behind the ball, was that
`attempts to clean this top frac port kept producing proppant upon each attempt to clean the interval.
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`Eventually it was decided to move forward with the completion and the 4-1/2” production liner was perforated with a short
`interval of large diameter charges.
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`The top interval received a mini-fracture to be certain that we could place the proppant, now through perforations in three
`strings of casing. The 20/40 mesh intermediate strength proppant had to pass through the 4-1/2”, 7” and the 9-5/8” casing.
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`IWS EXHIBIT 1053
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`EX_1053_007
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`Downloaded from http://onepetro.org/SPEFD/proceedings-pdf/08FD/All-08FD/SPE-112442-MS/2742148/spe-112442-ms.pdf/1 by Robert