Artificial Lift By Sekar Learning Advisor - Process TRAINING TARGETS The aim of this section is to help you gain a working knowledge of the function and operation of the different artificial lift methods. State the different types of Artificial Lift. Make a simple sketch of a gaslifted well. Identify the components on a beam pump. List the different types of beam pump units. Explain the operation of a beam pump. List the different types of subsurface pump. Explain in simple terms the operation of plungerlift system.Use one slide per model, if appropriate. INTRODUCTION •On a natural flowing well the reservoir pressure P1 available to push the liquid to the surface is reduce due to pressure losses in the system. •These pressure losses are; draw down pressure loss (P1-P2), vertical lift pressure loss (P2-P3) and tubing head pressure loss (P3). •If the reservoir pressure is greater than these three components then the well will flow What is the Artificial Lift? •Initially the reservoir pressure may be sufficient to sustain natural flow. •But it gradually declines as it gets older. •In these cases there maybe plenty of oil still to be recovered. •But assistance is needed in the production. •The methods use to recover the oil is called “artificial lift”. The two types of artificial lift systems use are: Gaslift Systems Pumping Systems FLOWING WELL PERFORMANCE Vertical Lift A significant amount of reservoir pressure is lost between the bottom of the hole and the tubing head. This is called the vertical lift pressure loss. The causes of vertical lift pressure loss in the system are: The vertical height of the column The density of the fluid The tubing head pressure PPTF •If the tubing head pressure is zero psi, the pressure at the bottom of the well will depend only to the vertical height of the well and the density of the fluid. This pressure is called the static bottom hole pressure or the hydrostatic head. The increase in pressure per unit increase in depth is known as pressure gradient. •This gradient is expressed in pounds per square inch per thousand feet or PPTF. •Gas gradient is in the range of 75-150 PPTF. Oil gradient is in the range of 300-400 PPTF. Water gradient is in the range of 430- 470 PPTF. PRESSURE AND DEPTH GRAPH Gradients are represented on a diagram or graph of pressure against depth. The figure shows the pressure/depth graph of fresh water. The gradient is a straight line and the pressure at any depth can be read off at the bottom. A well filled with fluid will have a pressure increase from the surface to the bottom. Flowing Pressure Gradient When oil, gas and water flow up the tubing there will still be a pressure gradient. The gradient in multiphase flow situation depends on the relative volumes of the oil, water and gas. It also depends on the density of each of these phases. Shown below is an example of a pressure flowing gradient. Artificial Lift methods used in BSP The methods of artificial lift used in BSP are: Gaslifting Sucker rod or Beam Pumping Plungerlift Electrical Submersible Pump GASLIFT The technique of increasing the flowing life of a well by the injection of gas into the tubing is known as gaslift. There are two methods of gaslift: 1) Continuous gaslift 2) Intermittent gaslift Continuous gaslift: •Relatively high pressure gas is continuously injected into the well casing from where it enters the tubing through gaslift valves located at intervals along the length of the tubing. •Due to the "aeration" of the fluid column the density of the column is reduced. Intermittent gaslift: •Although grouped with continuous gaslift, intermittent lift is an entirely different type of artificial lift. Gas injected in short burst into the annulus, causes the ball valve at the bottom of the tubing to close and pushes a slug of liquid from the bottom hole to the surface. •The gas is then shut off and the ball valve opens to allow fluid to build up for the next slug. DEPTH OF GAS INJECTION •In gaslifting, gas is injected from the annulus into the tubing somewhere down the well. •But how deep should this injection point to be? We can inject the gas down to the deepest point of the well but there are limitations to this. •To determine this limitations, an example is illustrated based on the pressure depth graph. DEPTH OF GAS INJECTION Example: A vertical well is 10,000 feet deep. The tubing is filled with a liquid gradient of 450pptf. The pressure in the tubing at the surface is zero psi. A straight line is drawn between the points zero pressure at surface (zero feet) and 4500 psi at 10,000 ft. This line is called the “static pressure gradient line of the liquid”. If the gas supply pressure at the surface is 1000 psi and the gas gradient is 150 pptf, the pressure in the annulus is: 1000 psi + (10000 x 150)/1000 = 1500 psi at 10000 ft. The two points for the gas gradient are: 0 feet – 1000psi 10000 feet – 2500 psi DEPTH OF GAS INJECTION The two lines will intersect at a depth of 3333 feet. At depths above 3333 ft the gas pressure in the annulus is higher than the liquid pressure in the tubing. Gas would be able to flow from annulus to tubing. At depths below 3333 ft the gas pressure in the annulus is less than the liquid pressure in the tubing. Gas could not flow in the tubing. It would appear that the maximum depth at which we could inject gas into the tubing is slightly less than 3333 feet. In gaslift situation it is advantageous to inject the gas as deep as possible. KICK OFF •Kick off is a technique whereby gas is injected through a number of injection points in turn. This technique will be able to deepen the point of injection. •If we are able to inject gas at a point just above 3333 feet, the gas bubbles up the tubing. This has the effect of reducing the gradient of the fluid in the tubing and pressures at all points in the tubing will decline. •`The gas gradient in the annulus will not change. So the point at which the annulus and tubing pressures are equal will be deeper in the well. •If we could now start injecting gas at this point, an even greater length of tubing would benefit from the gas. Once again the pressures in the tubing below the point of injection would further decline. •The point of balance between the tubing and annulus pressures will even be deeper. KICK OFF GASLIFT VALVES A gaslift valve is like a pressure regulator. Its function is to admit gas from the annulus to tubing as required. Wireline retrievable gaslift valves are normally located in the “side pocket mandrel”. CAMCO BKR III The CAMCO BKR III is a fluid sensitive valve. •Tubing fluid acting under the larger surface area if the bellow added to the casing press acting under the small surface area of the valve is the opening force. •When this combined force overcomes 'Bellows Pressure' the valve will move off its seat and injection will start. •The valve will continue injecting until the tubing fluid gradient is reduced when a valve lower in the tubing string is open. •When this happens: •'Bellows pressure' overcomes 'Tubing pressure' + 'Casing Pressure' and the valve closes. APPLICATIONS OF GASLIFT Gaslift is a flexible system and can be applied in a number of situations: To artificially lift wells which will not flow naturally To kick off or unload wells To increase production rates in naturally flowing wells ADVANTAGES It is flexible and can be designed to operate over a wide range of changing well conditions Poses fewer problems in highly deviated wells No moving parts downhole •DISADVANTAGES There must be an economically available supply of gas. Gas compression facilities may be required Casing and wellhead equipment must be able to withstand the applied pressure Gaslift is not so efficient for high viscosity oils GASLIFT SYSTEM A typical gaslift system comprises the following components: (a) A source of high pressure gas (compressor or gaswell). (b) Distribution lines to bring the gas to the wellhead. (c) Surface controls. (d) Subsurface controls (gaslift valves). (e) Flow lines. (f) Separation equipment. (g) Storage facilities. (h) Flow measuring equipment. GASLIFT SYSTEM BEAM PUMPING •The pumping unit is that part of the installation at the surface used to change the rotary motion of the prime mover (electric motor) to an up and down motion of the sucker rods at the required speed. Speed reduction between the electric motor and the pitman crank is accomplished by a combination of V-belt drive and gear reducers. The crank is rotated by the slow speed shaft on the gear box. •With one end of the pitman connected to the crank and the other end to the walking beam, the rotation is changed to the up and down motion required to operate the subsurface pump. •A set of weights, attached to the crank, counter-balances the weight of rods and part of the weight of the fluid which is hanging from the front end of the walking beam (horsehead). These counter balances assist the electric motor to lift the rods and fluid on the up-stroke. BEAM PUMPING UNITS In BSP there are two different types of Beam Pumping Units, the Conventional Unit and the Air-balanced Unit Conventional Unit - Pulling action: The conventional pumping unit is normally crank-balanced and is the most common unit currently in use in BSP. The rotation of the crank causes the walking beam to pivot about the centre bearing. BEAM PUMPING UNITS BEAM PUMPING UNITS Air-balanced Unit - Push-up action: •On the air-balanced pumping unit the load is counter- balanced by the use of air pressure working against a piston inside the cylinder. •A counter balance device is employed to adjust the air pressure to the level required for perfect counter-balance even though the well condition may change from day today. BEAM PUMPING UNITS Air-balanced Unit BEAM PUMP OPERATION STUFFING BOX The rod string is lifted by means of a cable (bridle) looped over the horsehead and connected to the top member of the rod string which is called polished rod, by the carrier bar and polished rod clamp. Pumping well pressure is sealed, or packed off, inside the tubing to prevent leakage of liquid and gas past the polished rod. This seal is called the stuffing box. FMC PACKINGS •Le Grand packings are being slowly changed to FMC packings complete with flapper valve and single block FMC trees. •The purpose of the flapper and single block tree is to be able to contain and control well pressure during a sucker/polish rod failure. • The stuffing-box packing is replaced when it becomes worn and no longer seals. Below the polished rod are the sucker-rods. •These are solid steel or fibreglass rods running inside the tubing string connecting the subsurface pump to the pumping unit. •Sucker-rods are joined by sucker-rod couplings or by box-pin coupling. FMC PACKINGS SUBSURFACE PUMPS Subsurface sucker-rod pumps are cylindrical, reciprocating, positive displacement pumps that lift liquid from the well to the surface. They are divided into two general types: Rod pumps. Tubing pumps. SUBSURFACE PUMPS Operating principle The subsurface pump operating principle is briefly described as follows. The pumping cycle starts with an upward stroke of the rods, which strokes the plunger upward in the barrel. The travelling valve closes, the standing valve opens,and fluid enters the barrel from the well. On the downward stroke of the rods and plunger, the standing valve closes, the travelling valve opens, and the fluid is forced from the barrel through the plunger and into the tubing. Fluid is lifted toward the surface with each repeated upstroke. PLUNGERLIFT •Plungerlift is a special method of gaslift, as reservoir pressures in the Seria Field since continuous gaslift has become increasingly inefficient. •Usually this has been overcome by converting wells to beam pump. •However, for certain types of wells conversion does not work because of sand and wax problems. •Plungerlift is a suitable alternative. PLUNGERLIFT PLUNGERLIFT PRINCIPLE OF OPERATION •Plungerlift consists of a plunger cycling up and down the production tubing, carrying, in each cycle, a slug of produced liquid. •The plunger acts as the interface between the produced liquid and the injected gas, which drives the plunger to surface. •The plunger prevents significant liquid fall back, thus improving lift efficiency.