TECHNICAL BENEFITS OF CJS / RAISE HSP. Technical Advantages

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1 TECHNICAL BENEFITS OF CJS / RAISE HSP Technical Advantages The HSP is designed for low- to mid- volume applications at flow rates of 1 cubic meter to 30 c. m per day. The benefits are in the details. The pump's positive displacement design is ideally suited for horizontal and deviated wells. The HSP is free of moving parts or rotating rods. The new pumps have been significantly better than the PC pumps due to reduction in tubing wear. Kurt Bair, senior petroleum engineer, Storm Cat Energy. Ease of Operation The HSP's clamshell- hooded surface unit is easy to use and easy to maintain. The entire enclosure opens so that all mechanical components are within reach. There is no access panel. The enclosed surface unit is the only one of its kind in the industry. It is extremely compact and quiet and easily serviced from above ground. The pump rate can be manipulated using a flow divider (Fig. 1) to produce daily volumes of.1 to 25 cubic meters. This change occurs almost instantly. The flow control valve is located in the surface equipment where it can be easily adjusted. Fig. 1 Flow Divider The flow of hydraulic oil to the bottom- hole pump dictates the cycles of the pump while the speed with which the oil is sent dictates the frequency of each cycle. A single joystick in the surface unit determines the amount of oil sent to the bottom- hole pump. It takes one gallon of oil to extend the cylinder and 3/4 gallons to extract the cylinder. For every 1.7 gallons of hydraulic oil pumped from the surface using the joystick the bottom hole pump produces one gallon of water. Changing rates are easy to accommodate. The range of an HSP is absolutely infinite whereas other pumps in the industry are limited in

2 their range. For example, an ESP requires a service rig and a complete reinstallation to accommodate volume fluctuations. In contrast, the well deployed with an HSP for two weeks could produce 10 cubic meters of water daily. Inflow levels will not overflow the pump. The joystick can manage changing rates and the rate needed to cycle the bottom- hole pump can be determined quickly. This makes it easy to keep the well unloaded. Ease of Installation The pump can be installed and running within one half- day thanks to its FlatPak coiled tubing deployment and activation. Coiled tubing enables quick installation of an HSP because it eliminates the need to thread piping together. From service to bottom hole, the pump takes little over an hour whereas jointed pipe takes more than a half- day to install. The HSP capitalizes on all the benefits of coiled tubing, which is also less expensive than other tubing choices. Average HSP installation schedule: Rig up 8 a.m. to 10:30 a.m. Pump is run into the well at 11 a.m. Pump is on bottom at 1 p.m. Surface unit and pipeline are tied in at 3 p.m. The surface unit is started and the system starts pumping water. Ease of Removal and Redeployment The system is easily removed and re- installed. The HSP runs on three coil tube lines, two hydraulic entry lines and one production exit line. The coiled tubing unit is self- contained and FlatPak ready. The entire system can be removed, installed in an alternate well and functional within a day, taking into account all service utilities. To remove the HSP the hydraulic lines are detached and the surface unit is loaded into a trailer. The tubing is collected and the assembly is removed from the well. Then the pump is disconnected and the well is capped. The surface equipment is entirely self- contained, there are no building pads to lay and no pump assembly is required. There are simply four fittings and two fluid connections to make to set up the HSP. Success with Frac and Formation Sand The pump is fitted with a 10- slot self- flushing sand screen, which filters larges particles of frac sand, coal and cement. The sand screen is a 1.3- metre tube of 1.5- inch outer diameter with inch spiral slots. The intake ports of the pump are located within the screen, filtering particles larger than 0.01 inches. The fluid exhausted from the cooling

3 chamber back flushes the screen clear with each stroke as the HSP pumps particles out of the well. Unlike other pumps, the HSP has no issues associated with rods spinning inside the tubing or sand being pumped in. It does not have the problems associated with wear on moving components such as rods and tubing caused by corrosion. Success in Harsh and Deep Environments A November 2006 study by the Pembina Institute, a leading independent, not- for- profit environmental policy research, consulting and education organization, revealed that the HSP pump efficiency, the ratio of output to input power, was either or superior to that of the conventional pump jack, progressive cavity pump and hydraulic pump jack. The HSP is an ideal shallow gas exploration device but it was also built for harsh and deep environments. It is designed to fit four- to seven- inch casing and it has been deployed in depths of up to 1,400 meters. Industry has questioned the HSP's ability to operate at depths greater than 2,000 feet or about 607 meters. However, the HSP has operated at full performance in well depths of up to 4,600 feet or 1,400 meters. The speed and function of the HSP's hydraulic fluid and piston enable the pump to work in very deep conditions. Performance of the pump in field applications in 2006 and 2007 demonstrates the merits of a hydraulic power approach to downhole pump applications. Heat Trace The HSP has an inherent heat trace system that prevents the wellhead from freezing. The system recycles excess hydraulic oil, which manages the temperature of the wellhead. Hot oil routed along flow lines is circulated through the hydraulic hose. It inherently heats when it is pressurized. This system is not dependent on electricity. This becomes a necessity in remote areas where electricity might not be accessible. A hose is wrapped around the water piping and insulation is wrapped around the hose, which prevents freezing. The pipeline acts as a heat exchanger. It is not necessary to cool oil and generate heat by other means since heat trace occurs naturally in the HSP. This system is beneficial because it is cost- effective and energy efficient as no extra energy is used to generate heat. The HSP does not require a radiator or fan. Gas Lock Prevention The HSP is not reliant on the presence of water in its piston chamber to function, unlike other types of downhole pumps. Positive displacement design of the cylinder and a 100 percent seal enables the pump to move gas just as efficiently as water. Pump volume is based on well depth. This ensures that the cylinder will compress gas at minimum bottom- hole pressure to exceed maximum tubing hydrostatic pressure.

4 The HSP pump is designed to prevent gas locking. Gas locking will occur when clearance volume, defined as the geometric volume contained in the piston chamber at the end of the stroke, is less than the critical volume relevant to gas locking pressure. These volumes are related to varying pressures by the thermodynamic law of compression under adiabatic and isentropic conditions: V1 / V2 = P2 / P1 y1 Here, V1 is the volume in the piston chamber at the end of the intake stroke of the pump; V2 is the volume occupied by the compressed gas at the end of the production stroke; P1 is the pressure of the gas when admitted into the chamber; and P2 is the pressure of compressed gas at the end of the production stroke. The exponent r is the ratio of the specific heats of the gas cp/cv. For natural gas mixed with air, this ratio is about When P2 equals the hydrostatic pressure in the coil one obtains values for V2 that establish the critical clearance volume for gas locking. Table 2 below uses V2 as a function of pump depth, which corresponds to the hydrostatic head of the water column in the coil. Gas locking occurs when gas becomes trapped in the piston chamber. In the HSP pump, this scenario is impossible because of its geometry. Water is moved up to the surface by a piston which pushes the water out of the piston chamber, passed a check valve and out to the coil connecting the pump to the surface. The water column contained in the coil rests against that check valve, with a pressure equal to the hydrostatic head of the column. Hence, water can only flow past the check valve when the pressure imparted by the piston on the water in the chamber exceeds that of the hydrostatic pressure. There are times when gas enters the chamber along with water flows. This gas is compressed during the piston stroke. Gas locking would normally occur when gas entered the chamber in the absence of water. If at the end of the piston stroke the gas pressure is less than the hydrostatic pressure in the water coil the check valve will not open. In this case, the piston becomes gas locked and unable to move any gas to the surface. Table 2. Critical Clearance Volume for Gas Locking The HSP pump exhibits a clearance volume of about two cubic inches, which is less than the calculated values for V2. Operation in a Pumped- off State A pumped- off state occurs when there is no water left downhole. The ability to continue pumping under this condition is inherent in the design of the HSP. In this scenario, the water piston does not produce a flow through the check valve, although it may contain residual water inside the chamber. Gas will be pushed out through the water coil since gas locking cannot occur.

5 The positive displacement design of the pump allows it to continuously pump up to 100 percent gas for prolonged periods of time. In practice, the pump should not be operated for more than eight hours in the pumped- off state, to prevent the possibility of dry- running of the middle gland seals. Determining a Pumped- off State Operators can readily determine if the well has been pumped- off while the system is in operation by monitoring the gauge pressure of the oil flow as it leaves the surface pump. A gauge located above ground at the wellhead easily determines the amount of gas in the pump. When water is present in the coil the surface unit generates a pressure surplus in the oil coils to raise the water column. The surplus shows up as a large pressure maximum on the gauge. When water runs out downhole, the pump is no longer pushing against the water column. Consequently, the pressure maximum read from the surface gauge will be noticeably lower, while the pump driver's rpm will momentarily speed up to account for reduced resistance. This ability to rapidly detect the sudden water cutoff downhole, without the need for reading the flow conditions downhole, is unique to the HSP design. A pumped- off state is easily determined without fluid shots or down- hole gauges. The hydraulic pressure gauge detects gas interference or compression. When the pump is lifting fluid at full stroke the gauge will show the pressure required to lift it. If there is gas in the pump, it must be compressed to equal the pressure of the fluid inside the tubing. When a normal working pressure level is reached contents are sent to the surface. Furthermore, and operator can gauge the downhole pressure in a similar fashion while the surface unit increases the initial pressure in the oil coil until water flow is produced. Given the depth, coil sizes and surface pressure in the oil coil, the downhole pressure can be determined either from the pump's performance curves, or by a quick calculation based on the friction losses in the coil.

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