The initial PCP pump run in an oil well was done by Griffin Pumps in September of 1980 at Lloydminster Saskatchewan Canada and, based on the outcomes of that test, 5 additional were run in January 1981. These uses were all in heavy sandy oil wells. Since then the PCP pumps have been employed in lighter, higher water cut wells of up to 35 API and 100 % water and volumes as high as 650 m3/day.

The screw pump advantage over other forms of artificial lift such as beam pumping and ESP is that it can deal with solids such as sand and operate at a more economic cost with less maintenance.

The PCP pump can greatly improve the economics of a field in two ways:

A) lower capital cost

B) reduce operating cost

Another benefit of the screw pump system is that it uses the same tubing and rods as conventional beam pumps and the rotor landing procedures are similar to that of spacing out the plunger on a traditional rod pump. This results in least possible training for service rig personnel.

The concept of the PCP pump is to generate pressure and lift the fluid. This is done by creating equal and separate cavities throughout the pump length as the rotor rotates in the stator. Some pumps will have as many as 50 or new cavities, depending on the lift requirement. The differential pressure necessary to lift the fluid is then split equally among all the cavities. Therefore, on a pump with 50 cavities, the differential pressure across each cavity is 1/50th of the total requirement.

With the differential so low across each cavity, softer elastomers that can deal with sand can be utilised.

Pump action results when the rotor is turning in a clockwise direction in the stator and each rotation of the rotor will displace 2 cavities and create 2 cavities at the inlet of the pump. This is due to the fact that, in a PCP pump, the rotor is an external single helical gear and the stator is a double internal helical gear. This is what is commonly known as a 1:2 geometry pump.

Therefore you can increase and decrease the output of the pump by merely changing the rotor speed. Speed is relevant to production. Theoretically, the faster the rotation of the rotor, the higher the output of PCP pumps. The actual production of the pump will vary and will be somewhat less that the theoretical production, due to pump slip. As you increase the differential pressure across the pump the slip volume increases. To offset the slip and to keep up a constant production volume, you can increase the speed.

As you draw the fluid level down, the differential pressure increases and the slip will also increase resulting in a decrease production rate. This is what is referred to as pump efficiency.

The PCP pump slip can be controlled by rotor /stator fit, by using a tighter fit for higher efficiency and low speed for heavy oil and a looser fit for lower efficiency and higher speed for light oil.

The pump has two parts: the rotor and the stator. As far as repair and maintenance of these two components is concerned, once the stator is damaged or the rubber is swollen, it has to be replaced; the rotor can be rechromed if there is no damage to the core itself.

The drivehead consists of three parts: the bearing that holds the rod weight, the back spin control and the drive mechanism. There are many types and styles of drives manufactured all over the world; however, they all incorporate the three basic functions of the drivehead.

All drive heads are equipped with a backspin retarder or brake that controls the spring torque stored in the rod string.

When the unit is shut down or looses power, the rod torque will unwind and, as the fluid level equalizes, the downhole screw pump turns into a motor, turning the rod string from the bottom. Therefore, it is very important to have a check valve on the flow line as close to the well head as possible, to prevent the fluid from flowing from the flow line back down the well.

Anchoring of the tubing is important on the larger PCP pumps where the pump torque is higher than the tubing makeup torque and, if the service rig is not equipped with power tongs to torque the tubing connections to the optimum value. Since the reactive torque of the stator is left-hand, the tubing will back off and part, if it is not torqued correctly or anchored.

In order to keep optimum production it is important that the bottom hole pressure is not drawn down below the bubble point. When this happens, free gas will enter the pump and the pump efficiency will drop off dramatically. The pump will not gas lock and, to try and offset this problem, the pump inlet should be lowered below the perforations and in extreme circumstances a downhole separator should be employed.

A fluid level above the PCP pump must always be maintained, because this pump requires net positive suction pressure in order to operate, or otherwise the pump will not suck.

This information is kindly presented from the author\’s seminars. Visit the PCP pump website to learn more about Canam\’s own PCP system (the Twister), or the main oilfield equipment website.

This information is kindly provided from the author\’s seminars. Visit http://progressive-cavity-pumps.Canamservices.Com find out more about Canam\’s own PCP system (the Twister), or the main oilfield equipment website at http://canamservices.Com.

Author Bio: This information is kindly presented from the author\’s seminars. Visit the PCP pump website to learn more about Canam\’s own PCP system (the Twister), or the main oilfield equipment website.

Category: Business
Keywords: pcp pump, progressive cavity pumps, artificial lift, oilfield equipment