Selection of Artificial Lift Systems for Deliquifying Gas Wells Page 10

Selection of Artificial Lift Systems for Deliquifying Gas Wells Page 10

Status

·  Document written and edited

·  Chair: Cleon Dunham,

·  Team: Not applicable

·  Comments: Not applicable

1.6 Know Your Reservoirs

This describes the knowledge you must have about your reservoirs; their recoverable reserves, the primary drive mechanism(s), the static bottom-hole pressure, etc.

-  Reserves

If you are considering a significant expenditure on artificial lift equipment, it is essential to know the “size of the prize.” In other words, how much gas is in place in the reservoir, how much of this is recoverable, and how much is recoverable by the artificial lift method(s) that are being considered? Clearly, the recoverable gas must be sufficient to justify the expenditure that is contemplated. Normally, this is not a question that can be answered by the Artificial Lift Staff, but will require input from Reservoir Engineering.

§  Gas in place

To determine the gas reserves, certain tools are required and certain data is needed to make these tools work properly. Some of the important variables are:

-  Area. This is the area of the reservoir, or more particularly the drainage area that can be drained by the well of interest. Is it 640 acres, 40 acres, or some different size? The drainage area available to the well of interest is a function of the number of wells drilled in the reservoir, where they are located in the reservoir (e.g. up dip, down dip, etc.). Another factor is interference of offset wells. If offset wells are produced at high rates, this may limit the amount of gas that can be produced from the well of interest.

-  Height. This is the height or thickness of the reservoir. The area times the height gives the volume of the reservoir that can be drained by the well of interest. Clearly, the height is not necessarily constant across the reservoir. The value needed here is the average height.

-  Porosity. This is the portion of the overall reservoir volume that is not filled with solid rock. In other words, this is the pore space where gas may be accumulated. Again, the actual porosity may vary across the reservoir, so the average value is needed here. The volume of the area times the height times the porosity gives the volume of pore space in the reservoir.

-  Water saturation. Some of the pore space may (will probably) be filled by water. This limits the amount of pore space that is actually filled with gas.

-  Bottom-hole pressure. Gas is compressible. The actual amount of gas is a function if the volume and the pressure. At lower reservoir pressure (static bottom-hole pressure or SBHP), the gas is expanded and less is available in the reservoir to be produced.

-  Bottom-hole temperature. Temperature also has a significant impact on the volume of gas. The higher the temperature, the greater the pressure of gas in a specific physical volume.

-  Pressure build-up. A pressure build-up test is conducted by measuring the reservoir pressure over time after a flowing well is shut-in. The shape of the build-up curve, and the amount of pressure build-up, can provide significant information about important reservoir properties. Pressure build-up surveys are not free. The well must be shut-in which means that production is stopped. Also, there is always some risk when pressure measurement instruments are run in a well.

-  Production analysis – type curves – Topaz, RTA. There are various tools available to evaluate pressure build-up data. The Reservoir Engineer should have access to these tools and know how to use them.

-  Darcy’s Law. Darcy’s Law is a well known method for calculating the flow of fluids from a reservoir.

-  P/Z calculations. A method for calculating remaining producible reserves is use of P/Z calculations. This process will be described in an annex to this Recommended Practice.

-  Reservoir simulators – Eclipse. Modern, computerized reservoir simulators can be used to estimate remaining producible gas reserves. The Reservoir Engineer should have access to Eclipse or other reservoir simulators.

-  Abandonment pressure

If the reservoir produces under depletion drive, it is important to now the abandonment pressure. This is the minimum reservoir pressure where enough gas can still flow from the reservoir to the wellbore to sustain an economical production rate. Knowing the abandonment pressure may have a significant impact on the type of artificial lift system chosen to produce the final remaining reserves in a reservoir.

·  Other factors that may affect the amount of gas that can be produced

-  Fractures vs. permeability. A major factor in the production of reservoirs is access to the gas in the reservoir by the wells. Permeability describes the ability of the reservoir to support flow of gas and liquids through the reservoir. If the permeability is high, flow into the wellbore can be easy. If the reservoir is very tight and has very low (or no) permeability, it may be necessary to fracture (break) the reservoir rock to allow flow to occur. Now access to the gas depends on the size, type, and quality of the fractures.

-  Reservoir drive mechanism – water drive, depletion. Another factor is the reservoir drive mechanism. If a reservoir has a strong water drive, water may enter the reservoir as gas is produced. This may maintain the pressure in the reservoir at or near its original value. If the reservoir has no or limited natural water drive, it may be possible to supplement this by water injection. If there is no water drive or injection, the reservoir pressure will decrease (deplete) as the gas is produced. This will reduce the drive mechanism to move the gas to the wells.

-  Trends in pressure over time. It is important to keep track and plot the trend in static bottom-hole pressure over time. This provides important information on the type of reservoir drive mechanism – water drive, partial water drive, depletion drive, etc. It is also important information for use in reservoir performance models, P/Z calculations, etc.

-  Multiple zones open in a wellbore. A major factor can be the numbers of zones (or actually the number of separate reservoirs) that are open (perforated) in a wellbore. If more than one zone or reservoir is open to the wellbore, this may lead to unequal production or depletion of the separate zones, the potential for cross flow or loss of liquid into lower pressure zones, and other potential problems.

-  Inflow from Reservoir to Wellbore

Once the amount of gas in the reservoir that can be produced is known, the next important factor is the ability of this gas to be produced from the reservoir to the well. A number of factors are important in this determination.

·  IPR

One of the most important factors is the inflow performance relationship or IPR. This relationship describes the gas inflow rate as a function of the operating or flowing bottom-hole pressure. Since different types of artificial lift can achieve and sustain different operating or flowing bottom-hole pressures, it is very important to know the IPR for each well. And, in most cases, the IPR is different for each well in the same reservoir, for many reasons. Therefore, it is important to determine the IPR for each well on a periodic basis. And a well’s IPR can and will change over time as reservoir conditions and inflow conditions change.

·  IPR curve – Vogel

There are various ways to describe the inflow performance relationship. One of the best known and simplest to use is the Vogel method. This is described in detail in an annex to this Recommended Practice. The Vogel method was developed for solution (depletion) drive oil reservoirs but it works acceptable well for gas reservoirs.

·  Backpressure tests – Fetkovich

Another method is the one developed by Fetkovich. If one wishes, this may be used in lieu of the Vogel method.

·  Data needed to determine IPR

The following information is needed to determine the Inflow Performance Relationship for a well.

-  Bubble point pressure. The IPR curve behaves differently above and below the bubble point pressure. Therefore, the bubble point pressure and its relationship to the Static Bottom-Hole pressure must be known.

-  SBHP. The static bottom-hole pressure (SBHP) must be known. This can be determined from a Pressure Build-Up Test (discussed above) or from a SBPH pressure measurement. If the reservoir does not have a strong water drive, the SBHP will change with time; so it must be determined or accurately estimated on a period basis. A frequency of at least once per year is recommended.

-  FBHP. The flowing bottom-hole pressure (FBHP) must be determined in conjunction with a well test. The best way is to measure the FBHP during a stable well test. If this is not possible, it may be possible to infer the FBHP based on fluid level measurements or vertical pressure calculations,.

-  Production rate. The well’s production rate must be measured at the same time as the flowing bottom-hole pressure. Ideally the well test should be taken during a stable production period, when the flowing bottom-hole pressure in the well is stable and being measured.

-  Impact of type of reservoir on ability to obtain SBHP. In some cases, the type of reservoir may impact the ability to obtain an accurate static bottom-hole reservoir. If the reservoir is very tight, it could take a long time (days or weeks) to obtain a fully built-up static reservoir pressure. In a fractured reservoir, the SBHP measurement may only “see” the pressure in the parts of the reservoir that are in communication with the wellbore via the fracture system. In some cases, it may be possible to overcome these problems with special pressure build-up analysis or reservoir simulators.

-  Inflow constraints – skin, damage, water blockage. Many factors can affect inflow performance other than “normal” reservoir parameters such as area, porosity, permeability, etc. These may include skin, near wellbore damage caused by invasion of drilling materials, blockage caused by water invasion into the reservoir from the wellbore, etc. Detection and treating of these is a science all by itself. If inflow constraints are expected, it is best to consult with an expert Production Technologist who is familiar with this type of diagnosis and treatment.

-  Productivity – relative permeability – water imbibition into reservoir. Since the primary focus of these recommended practices is gas well deliquification, a major issue is the impact of water accumulation in the wellbore on the reservoir and its productivity. This is not a perfectly well understood subject, but it is well known that a continuous level or head of water in the wellbore can allow or cause some of the water to enter or be imbibed into the reservoir. And it is well known that higher water saturation in the near wellbore region will have a negative impact on the productivity of gas. And, it is well documented that it can sometimes take a long time to remove water from the formation once it has been allowed to accumulate there. All of this argues for the importance of removing water from the wellbore and not allowing it to stand or accumulate over the formation interval.

-  Other Important Reservoir Factors

There are a number of other factors that must be considered and understood to optimize gas recovery from reservoirs.

·  Reservoir treatments

It is important to know what reservoir treatments have been conducted and if any are anticipated. By reservoir treatments, such things as secondary recovery projects (e.g. water flood), acid stimulations, fracture jobs, etc. are included. Each of these can have a major impact on the productivity of the reservoir.

·  Gas properties

Clearly it is important to know the composition and properties of the gas. This includes knowledge of such things as:

-  Gas/condensate ratio.

-  Gas/water ratio.

-  PVT properties.

-  Gas composition (hydrocarbon make-up).

-  CO2 content, if any.

-  H2S content, if any.

-  Paraffin content, if any.

-  Tendency to form scales

-  Solids content, if any.

·  Hydrocarbon make-up of condensate

It is important to know the hydrocarbon make-up of any condensate that is associated with the gas. This can have a significant impact on the choice of surfactants or other chemicals that may be used as part of the artificial lift system.

·  Source of water – formation, condensation, fracture water

It is important to know the source of water that needs to be removed from the well. The reason is that the strategy to remove this water may be very different depending on its source.

-  Is the water being produced from the formation itself? If yes, this may mean that the reservoir is a water drive or partial water drive reservoir and this may have a significant impact on the choice of artificial lift system.

-  Is the water being condensed from the gas as the gas cools during production? If yes, the primary strategy may be to prevent the condensation in the wellbore.

-  Is the liquid water that was injected during a fracture job or an acid treatment? If yes, one form of artificial lift may be required to remove this water and another form of lift, or perhaps no lift at all, may be required once the treatment water has been removed.