Various approaches connect wells to facilities

Ken J. Vargas
Falcon EDF Ltd.
Calgary

• Gas Well Decisions Flow Chart (Fig. 1 [142,506 bytes])
• This single oil-well battery handles 3 MMscfd. It is equipped with a treater, amine-sweetening unit, and amine acid gas incinerator for H2S disposal (Fig. 2 [30,552 bytes]).
• Thunder Energy Ltd.'s Rosalind sour oil battery handles 1,600 bo/d (Fig. 3 [25,332 bytes]).

A detailed analysis of existing processing and transportation facilities must be performed to determine the requirements for tying in new wells. A number of techniques are available.

This series of two articles discusses existing techniques and methods to quickly and effectively connect wells to production facilities and pipelines, typically used in western Canada.

This first article will discuss general considerations and the concluding part will cover detailed design.

Gas wells

Oil and gas production requires meeting certain product specifications and installing a distribution network.

Oil can be processed at the well site, trucked, or piped to a refinery. But a gas well, unlike an oil well, must be connected into a pipeline transmission system for the product to be sold. There are exceptions, such as if the gas is liquefied and transported in pressurized vessels. However, this process has been used in only a few areas of the world.

Identification of a typical gas sales specification is the first step in determining the type of gas processing needed to allow the gas to be transported without liquids or freezing, and in a state that the final consumer can burn cleanly and efficiently.

A typical gas sales specification is as follows:

• Dew point-15° C. at 850 psig
• Hydrogen sulfide (H₂S)-Less than 16 ppm
• CO₂-2 mol% maximum
• Pressure-950 psig
• Heat content-950 BTU/scf
• H₂O content-4 lb/MMscf
• Meter-Custody transfer, < (2% accuracy

Based on these specifications, the sales gas treatment may include some or all of the following four steps:

1. Removal of acid gas (H ₂S and CO ₂) by a sweetening process
2. Dehydration (H ₂O removal)
3. Hydrocarbon dew point control to remove rich hydrocarbons, leaving methane and ethane as the sales stream
4. Compression of gas to the pipeline pressure.

Sour gas

Many factors distinguish gas wells. The most important is H ₂S content. With H ₂S, the gas stream must be handled in a different manner than sweet gas because H ₂S is extremely toxic and lethal in small concentrations. A concentration of 500-700 ppm H ₂S in the surrounding air can cause a person to lose consciousness and possibly die.

Gas with H₂S is also corrosive and causes the associated gas to freeze in the presence of free water at a much higher temperature. Depending on pressure and concentration, this temperature is typically more than 80° F.

H₂S must be removed from a gas stream before the gas can be used as a fuel. Typically H₂S is removed with amine in a tiered contactor vessel.

A gas stream also can cause problems if it contains large quantities of CO₂. CO₂ is corrosive, and in combination with H₂S compounds processing problems. Most gas streams contain some CO₂.

When a gas contains more than 2-mol% CO₂, transmission companies will generally refuse the gas or charge a penalty for the low BTU content gas.

Lean/rich gas

Rich gas contains large quantities of hydrocarbons heavier than ethane. These heavier hydrocarbons drop out when the temperature is reduced.

As gas flows up the well bore and through flow lines, the pressure and temperature drop causes liquid hydrocarbons and water to condense. To avoid these liquids, pipeline companies require delivery of dry (without water) lean gas. In general most gases have to be refrigerated or processed to remove condensables such as propane, butanes, and water.

The decision flow chart (Fig. 1) provides general guidelines for deciding on processing alternatives. For a sour well, for example, the first decision is if the H₂S content is greater than 400 ppm. If yes, then the next step is to determine if hydrates will form either in the facilities or in the pipeline.

If the H₂S content is below 400 ppm, scavengers can be injected or used as contact agents to absorb the H₂S and sweeten the gas. The gas can then be processed in sweet-gas facilities at a reduced capital cost.

Both the scavenged and non-scavenged options require that the potential for hydrate formation be determined.

If the gas has no potential for hydrate formation, the gas is only metered before entering the sales pipeline. If hydrates might form, the gas is either dehydrated and transported through a noninsulated pipeline to sales or heated in a line heater and transported in an insulated line to sales. Dehydration is typically more economical than line heating for lines greater than 10-km long.

The sweet gas portion is treated in the same manner except that dehydration makes more sense because H₂S is not picked up by the triethylene glycol (TEG), and therefore is not released to the environment via the evaporated water of the regenerator effluent.

Oil wells

Oil wells can be classified by the produced crude such as heavy, intermediate, light, sour, sweet, waxy, and tightly emulsified. Emulsions are a dispersion of droplets of one liquid in another, immicible liquid, in which the droplets are of colloidal or near-colloidal size.

Three basic designations of crudes are:

1. Bitumen or extra-heavy crude has a viscosity above 10,000 cp and a specific gravity greater than one
2. Heavy crude has a viscosity below 10,000 cp and a specific gravity between 1 and 0.934
3. Light crude has a viscosity below 10,000 cp and a specific gravity below 0.934.

The objective of upstream crude treating is to remove water, salts, and sulfur, and to give the oil a viscosity such that it is easily transported in a pipeline, vessel, or truck. The tighter the emulsion, the more extensive it needs to be treated. To treat crude, the following may be required:

• Heat
• Settling or residence time
• Chemicals such as asphaltenes solvents, de-waxers, and de-emulsifiers.
• Electrostatic precipitators.

Crudes are typically treated to 0.5% bs&w, below 100 cp viscosity, and 10 Rvp, which means that the crude vapor pressure at 100° F. is 10 psia. These specifications provide a stable product with minimal volatility.

Sales specifications for crude vary widely and typically include penalties for noncompliance. For example, a crude over 0.85 specific gravity might be penalized for each fraction over 0.85.

As a rule, the specifications would apply to almost any crude for custody transfer to a pipeline or refinery.

Activity prior to sales includes:

• Well tests-Individual wells should be testing at least once every month. The testing should comprise a 24-hr period and include flow rate and oil, water, and gas analysis.
• Gas removal-Associated gas is removed by providing the crude with settling time and heat. This is typically achieved initially in an inlet separator and subsequently in a treater where heat, and/or electric current and chemicals are added. The chemicals and electric current are needed only if emulsions have to be broken.

For example, most gas will be removed by raising the crude temperature to 160° F. After treatment the crude will have an 8-10 Rvp.

Shipping the removed associated gas to sales is the same as for gas well gas except the facilities might be smaller than those for a gas well. In special circumstances the gas may be flared; however, this is not environmentally acceptable.

Fig. 2 shows a single oil well battery with treater, amine sweetening unit, and amine acid gas incinerator for H₂S. The facility can handle 3 MMscfd.

• Bs&w removal-Solids and water are removed to less than 0.5% volume. This can be done with gravity settling and water washing to remove the sand and treating the emulsion with heat, settling time, or chemicals. Tight emulsions may require electrostatic precipitation.

  Oil treating is not an exact science and familiarity with the crude helps to design a treatment.

• Crude storage-Crude is stored in atmospheric noncontaminated tanks to maintain the 0.5% bs&w. The crude should be stable after being treated to 10 Rvp.

  For sour crude, a blanketing and vapor recovery system is required because even with treatment H2S is still given off in small concentrations and must be contained to prevent it from becoming a public nuisance.

  Fig. 3 shows a sour oil battery designed to handle 1,600 bo/d.

Facilities specification

To begin the detailed design for the facilities, one requires the following data and documents:

• Well effluent analysis from DST (drillstem tests) or other well tests. These will be used for determining the characteristics of the gas, condensate or oil, and water.
• Well site survey showing the wells, access roads, power lines, flow lines, dwellings in the vicinity, and any special features.
• Closest tie-in point together with the pipeline right-of-way. The pipeline right-of-way should show all pipeline crossings before reaching the tie-in point, for example roads, creeks, rivers, cables, etc.
• Sales specifications and special requirements prior to entering the sales line or crude transport truck.
• Available utilities, such as sweet fuel gas, electrical power, water, etc.
• Special design constraints requested by the client.
• Project management by an engineer or engineering firm, for example engineering only (EP); engineering, procurement, and construction (EPC); or engineering, procurement, construction, and management (EPCM).

For oil wells one has to determine the transportation method such as pipeline or truck, and the method for disposing of the associated gas, either in a gas plant via a pipeline or flaring.

Oil wells typically have to be tested every 30 days and emulsion breaking history or laboratory analysis should be available to set guidelines for chemicals or treater temperature.

Once this information is compiled by the engineer, the project sign-off should then be received from everyone involved in determining the design basis. Once an agreement is reached, the engineer can proceed in designing the process equipment.

The next step is proper organization and storage of project information. This can be done with a three-ring binder (project manual) to store all project information. The project manual should contain the following information categories or divisions:

• Correspondence
• Design basis
• Surveys and site layout plan
• Project management (cost and schedule)
• Process design (process flow diagram, PFD, and material/energy balance)
• Regulatory requirements (government approvals/environmental considerations)
• Mechanical design
• Electrical/instrumentation design
• Quality control
• Major equipment information (bids, specifications, purchase orders, performance, etc.) for separators, compressors, line heaters, pumps, pipelines, refrigeration plant, etc.
• Construction.

Recombining well effluents

To recombine well effluents to simulate reservoir conditions one can perform an energy/material balance by using Hysim or other hydrocarbon process simulator to specify unit operations and associated streams.

If pipelines are involved, the flow can be simulated with a pressure/temperature drop program or calculation. This should be incorporated into the energy/material balance.

One can select and order the major/long delivery equipment by sizing them with the energy/material balance and write an AFE cost estimate and detailed schedule for the wells being tied-in.

The Author