Ex. BHA: Slotted Liner Cleanout

The GTS Rotajet

•  Remove Hard Deposits & Scale

•  Stimulate Openhole, Slotted Liner, & Perforations

•  Abrasive Perforating and Cutting

•  N2 Compatible for Underbalanced Well Clean Outs

•  Jetting Opens New Flow Channels to the Reservoir

•  Works With The Harshest Chemicals

•  Horizontal / Vertical Well Applications

•  Conventional or Thermal Wells

•  Can Be Used in Aggressive or Non-Aggressive Mode

GTS Rotajet Applications

15-03-26 3

•  Integral Cavitation – Pulsation – Vibration Module

•  Field Changeable Nozzle Configurations

•  Nozzles Suitable for Extended Use of Abrasives

•  Governed Rotation 30 – 50 rpm

•  Metal-Metal Dynamic Sealing: Allows pumping of nearly any chemical and unlimited use of N2

•  Pressure Balanced: Not limited by hydrostatic pressure due to depth

Features & Benefits

Rotajet Third Party Testing

•  Cemented 4.5” (114 mm) Sliding Sleeve

•  Jet-Cavitated at 2.2 BBL/min (350 l/min)

After

Before

•  Cement Completely Cleaned Out and Able to Open on First Attempt

BOE Motorhead Assembly

GTS Rotajet Tool, 2.5” (63.5 mm)

Coiled Tubing Connector

High Pressure Downhole Filter

GTS Fixed Blade Centralizer, 3.3” (83.8 mm)

GTS Fixed Blade Centralizer, 3.3” (83.8 mm)

Ex. BHA: Slotted Liner Cleanout

15-03-26 www.boeoiltools.com 7

Case Study #1 Successful 48 Hour Horn River Well Barium Scale Removal Well Description: Horizontal, High Bottomhole Temperature, Gas Production TVD: 9590 ft. (2923mTVD) Well Depth: 18606 ft. (5671mMD) Casing: 5-1/2” (139mm) BHT: 320ºF (160oC) BHP: 4350 psi (30 Mpa) Background – Removing scales and regaining well inflow was the objective of this multi-well campaign. Intervention method included the use of coiled tubing, 25% HCL acid, other additives and Rotajet wash tool. The wells had high bottomhole temperatures of up to 320ºF (160oC). Due to the age of the wells, the reservoir pressures had depleted to 4350 psi (30MPa) as an average. Solution – BOE was called to research and program a job design capable of removing barium scale to the max allowable depth of through tubing deployment method. It was mentioned that on 5 adjacent wells, the competitors reached depths 1000m shallower in 5 to 10 days compared to the depths of just over 5000m in less than 48 hrs. BOE set the tool string up to fit the application. Well configuration and clean out procedure was designed giving the operator the best possible chance in getting the tubing string to TD. Results - Though the scale was hard and progression reduced down to 0.33 ft./min (0.1 m/min) at times, the tubing string never stopped progressing and the BOE toolman had the experience to identify the downhole conditions that was causing the slow ROP. After 36 hours, the tubing reached max depth achievable in a through tubing application and the wellbore had scale removed to a known drift diameter. Based off of previous yard testing of similar configurations, not only was the drift ID achieved, but also the scale was most likely removed from the casing wall as well. Coil was pulled at a consistent slow speed to provide maximum coverage and wash over casing and placed acid evenly across perforated interval.

15-03-26 www.boeoiltools.com 8

Case Study #2 High Pressure Acid Squeeze on Central Alberta Foothills Well Well Description: New Drill, Horizontal Oil Well TVD: 9022 ft. (2750mTVD) Well Depth: 14557 ft (4437mMD) Casing/Liner: 4-1/2” Perforated (114mm) Background – A Drayton Valley, Alberta foothills well was licensed as a multi zone producing well with a fracture stimulation planned as part of the initial completion. During the completion, the casing integrity was compromised and unable to contain pressure preventing the planned fracture stimulation from being performed. It was decided to perforate 5682 ft (1732m) of the lateral followed by a high pressure acid squeeze as a contingent stimulation method for completing the well. It was desired to have as much acid as possible placed in direct contact with the formation rock. With the large amount of perforations exposed, an economical means of accomplishing this was needed. Solution – BOE was asked to provide the downhole coiled tubing conveyed tools needed for acid placement. Using the Rota-Jet tool, over 1900 bbl (300m3) of acid was pumped at high pressure directly into the perforation intervals. The slow rotating feature of the Rota-Jet gave the stimulation the best chance of effective acid placement. Results - Pump pressures exceeded 5800 psi (40MPa) and the bottomhole pressure was taken to just below the fracture pressure of the formation. The entire volume of acid was squeezed into the formation. BOE provided on site technicians and 24 hour remote observation of the stimulation.

15-03-26 www.boeoiltools.com 9

Case Study #3 Five Cold Heavy Oil Production with Sand (CHOPS) Injection Wells Cleaned Out and Stimulated Well Description: Long lateral, shallow heavy oil polymer injection wells TVD: 1542 ft. (470 mTVD) Well Depth: 7218 ft. – 8202 ft. (2200 mMD – 2500 mMD) Liner: 5-1/2” and 4-1/2” un-isolated slotted (139mm and 114mm) Background – Five polymer injection wells were chosen as part of a multi well clean out and stimulation campaign to improve the enhanced oil recovery program being operated in this field. These five injection wells had been experiencing progressive loss of injectivity. Maximum injection pressures of 1450 psi (10MPa) and an injection rate down to only a few cubic meters per day indicated the progressive build up of possible wellbore and near wellbore damage. Previous multiple well campaigns in this field showed little to no improvement both in the short and long term. Solution - Knowing that multiple potential causes may exist and together with the client, a unique clean out and chemical program were designed to treat the inner bore of the slotted liner, slots and the adjacent near wellbore of the unconsolidated sandstone reservoir. Coiled tubing was chosen for the treatment. A unique blend of chemicals were also chosen for 2 out of the 5 wells to aid in breaking down degraded polymer and other solids. BOE supplied the specially designed high pressure bottomhole assemblies for the stimulation. Results - Zero Non-Productive time attributed to BOE in 32 (24hour) days of operations. Tools withstood multiple cycles of insitu chemical exposure. Clean out program circulated out stator rubber, scales and sand from the wellbore (up to 30% sand cuts were experienced). 44000 bbl (7,000 m3) of high rate/high pressure fluid pumped through the same bottomhole assembly without damage or wash out. Competitive tools / techniques either failed within 8-12 hours or have shown questionable production results. BOE pulled and set retrievable bridge plugs and set up the BHA’s to deploy logging tools saving client money on additional field personnel. All five wells showed substantial improvements in injectivity. After 6 weeks of injection, the wells had not yet experienced steady state but continue to inject at 60% lower pressure as compared to pre-stimulation production data.

10 Extended Reach CHOPS (Cold Heavy Oil Production with Sand) Production Well Stimulation TVD: 1476 ft. (450 m) MD: 6562 ft. – 7546 ft. (2000m – 2300m) BHP: 580 psi (4MPa) Intermediate Casing: 9-5/8” (244 mm) Slotted Liner: 4-1/2”, 5-1/2”, 7” (114mm, 140mm and 178mm) Problem: Continuous oil production decrease and reservoir pressure distribution issues due to polymer flood localization. Traditional well treatments focused efforts on clearing liner inner diameter of solids. Low bottomhole pressure, low annular flow velocity and extended reach well configuration contributed to limited well cleaning. Slotted liner perforations never directly treated and suspected to be plugged with solids. Results: Well successfully cleaned to TD within AFE. Injection pressure decreased from 1450 psi to 870 psi (10MPa to 6MPa) surface pump pressure. Bottomhole assembly configured to hydraulically treat the slotted perforations directly. Initial production increase 1.3x - 2.5x oil volume and 3x total fluid volume with severe pressure fluctuations across the reservoir eliminated, allowing for a re-initiation of drilling activity.

15-03-26 www.boeoiltools.com 10

Case Study #4

2 Horizontal Limestone Injection Wells TVD: 3937 ft. (1200 m) MD: 8858 ft. (2700 m) BHP: 870 psi (6MPa) Production Tubing: 2-3/8” and 2-7/8” (60.3 and 73mm). Open Hole: 6-1/4” (159 mm) Problem: Continuous increased surface injection pressure due to build up of emulsion and possible skin damage. Difficult well treatment due to upper injection tubing string (through tubing intervention), low bottom hole pressure and open hole well configuration. Treatment program required solvent soak followed by acid squeeze. Results: Total depth achieved limited to tubing friction lock up. Hard scale plugs encountered and removed from segments in laterals (up to 360 ft. (110m) long). Injection rates improved for each of the wells: 8.7 gal/min @ 1450 psi to 158 gal/min @ 1450 psi (33 l/min @ 10MPa to 600 l/min @ 10MPa) 16 gal/min @ 1450 psi to 116 gal/min @ 1450 psi (60 l/min @ 10MPa to 440 l/min @ 10MPa)

15-03-26 www.boeoiltools.com 11

Case Study #5

Openhole Limestone Reservoir Oil Producing Well – SE Saskatchewan BHP: 1160 psi (8 MPa) Intermediate Casing: 7” (177 mm) Open Hole: 6-1/4” (158 mm), from 5568 ft.. – 9580 ft. (1697m – 2920m) Formation: Midale Background: Wellbore inflow of light crude oil reduced to 1.9 bbl./day (.3 m3/day) verses offset producing wells in the area 18.9 bbl../day (3 m3/day). Wellbore restriction and possible skin damage due to drilling was identified as the highest probability of the cause of inflow problems. Results: A two stage well stimulation was chosen. The first stage was performed using a service rig and drill bit to prove hole gauge. During the second stage of the stimulation, the BOE Rotajet Tool was ran to jet 250 bbl. (40 m3) of high pressure 15% HCl across the open hole lateral. The stimulation resulted in sustained 46 bbl./day (7.25 m3/day) production with an anticipated long term production rate of 19 bbl. (3 m3/day).

15-03-26 www.boeoiltools.com 12

Case Study #6