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Green Completions

Topic last reviewed: 1 February 2014

Sectors: Upstream

Well completion refers to the process that initiates the flow of petroleum or natural gas from a newly drilled well prior to production. This stream of fluids during well completions is referred to as “flowback”. During completion the reservoir is connected to the wellbore allowing the flowback of drilling and reservoir fluids (gas, oil, water, mud, etc.) to the surface. In a conventional well completion, the flowback period (also known as well cleanup) may involve flaring or venting of produced gas to the atmosphere via an open pit or tank collecting the fluids.

Well completions that involve hydraulic fracturing result in a higher rate of flowback than most conventional well completions, due to the large quantities of water and proppant (mainly sand) used to fracture lower permeability reservoirs. This high-rate flowback is generally composed of a mixture of fracking fluids with reservoir gas and liquids. For most wells, it takes from one day to several weeks to perform a well completion, during which the flowback mixture is typically released to an open pit or tank where the gas released from the liquids is vented to the atmosphere or flared depending on regulatory requirements or other factors. If the gas is vented, this may generate a significant amount of methane and hydrocarbon emissions to the atmosphere. Similarly, flaring generates a significant amount of combustion emissions, incurs product losses and is not always a viable option depending on the well location, the concentration of flammable gases in the flowback gas and other considerations.

In order to offset the loss of methane and other hydrocarbons during flowback, a technology known as Reduced Emissions Completions (RECs) or “green completions” may be implemented. Green completion is an alternate practice that captures the produced gas during well completions and well workovers following hydraulic fracturing. Portable equipment (Figure 1) is brought temporarily to the well site to separate the gas from the liquids and solids in the flowback stream, producing a gas stream that is ready or nearly ready for the sales pipeline.

Figure 1.  Truck-mounted green completions equipment. (Source: Weatherford. Natural Gas Star, 2010)

 

With green completions, a temporary system is used which consists of a skid or trailer mounted set of piping connections and vessels that include a plug catcher, a sand trap and a three phase separator (Figure 2). The plug catcher (not shown in Figure 2) is connected to the wellhead and is used to remove any large solids from the drilling and completion to avoid damaging other separation equipment [The sand trap removes finer solids present in the production stream, while the three phase separator removes water and condensate from the gas. Liquid hydrocarbons may be collected during completion and sold for additional revenue. Water is typically stored in water tanks or in a reserve impoundment for later treatment or disposal. If necessary, captured gas may enter a portable dehydrator at the well site or it may be routed to a permanent glycol dehydration unit in the gathering system, if one is available at or near the site, to remove heavy moisture from the gas before it enters the sales pipeline.

Figure 2.  Green completions equipment layout (Source: Natural Gas Star, 2011. Adapted from BP)

The equipment used during green completions is only necessary for the duration of the well completion. Therefore, equipment that can be readily transported from one completion site to another is more commonly used. A truck-mounted skid (as shown in Figure 1) is often used for transporting the equipment between sites. Oil and gas producers may use a third party service provider that rents the equipment, sets it up, and performs the green completion; however, in a large basin with high levels of drilling activity, it may be more economic for a producer to invest in its own green completion skid and carry out the operation themselves.

Green completions can provide environmental and economic benefits to oil and gas operations. The incremental costs associated with the capital investment of acquiring green completion equipment, or equipment rental and labor cost from a third party provider can be offset by the additional revenue from the sale of gas and/or condensate. If the technology improves over time and equipment-related costs are reduced, the revenues in gas and condensate sales may exceed the incremental costs.

Application of Technology

It could be technically feasible but may not be economically viable as REC equipment would have to be transported to off-shore site, or be permanently installed. Industry experiences have not yet been recorded publicly. Also, offshore developments typically have much fewer wells than onshore, so the benefits would be smaller and the costs higher and therefore not necessarily economically viable.  

Technology maturity

Commercially available?: Yes 
Offshore viability: No
Brownfield retrofit?: Yes 
Years experience in the industry: 11-20 

Key metrics

Range of application:
Well completions in unconventional gas formations (shale gas, tight sands, coal bed methane, or any low permeability, tight reservoir) involving hydraulic fracturing. Applicable for rehabilitation and redevelopment of mature wells (recompletions). Not recommended for low-pressure wells and exploratory (wildcat) wells located at long distances from a gathering system. Documentation recording the application of green completions in oil wells is not available. While green completions in oil wells may be technically feasible, it requires a gas pipeline infrastructure (and capacity) to be in place, which may not be the case in many oil formations. It could also be less economically feasible for oil wells as liquid hydrocarbon is the primary product instead of gas.
Efficiency: Recovery of up to 90% of flow back gas
Guideline capital costs: Purchased equipment one-time capital investment: around $500,000 for a simple REC set-up (values as of 2011). Payback time will depend on the amount of gas produced, gas prices and the utility rate (amount of wells completed per year) of the equipment. Payback time has been reported to be as little as 3 months by natural gas operators, but tends to be around one year on average [1].
Guideline operational costs: Third party contractors are often hired to perform conventional well completions. Many third party contractors also offer the equipment rental and labor to perform green well completions. Costs described here show are the incremental cost of using REC equipment - either hired ($600- $6,500/day) or purchased, and with labour costs only (~$300-$3,250/day), versus traditional methods of well completions. Costs vary per well depending on the characteristics of the flowback. High rate production wells may require larger equipment and longer well completion periods.
GHG reduction potential: Gas savings from avoiding flowback venting have been reported from 500 to 2000 MCF/day/well. Gas saved during green completions can be translated directly into methane emissions reductions based on the methane content of the produced gas. Amount of gas recovered can vary widely because it depends on a number of variables such as reservoir pressure, production rate, amount of other fluids (water, oil, solids, even and injected gases) lifted, and total completion time. EPA Natural Gas Star operators have reported that not all of the gas that is produced during well completions may be captured for sales [1]. Assessing the GHG reduction potential would be difficult to address in any meaningful way. We could make assumptions but there are many variables that go into the determination of the tonnes of CO2 including the methane content or the volume of gas vented during the well completion, the number of completions etc. This would be considered beyond the scope of our work on this topic paper as it would require substantial research to identify publicly available data.
Time to perform engineering and installation: Transportation and set up of REC equipment takes approximately 1 day. However this is dependent on location. Some basins are quite vast and travel time is much higher. This can be mitigated by scheduling the equipment to follow the drilling equipment since presumably drilling scheduled to minimize travel/down time.
Typical scope of work description: he decision process in planning an annual well completions program that includes REC technology consists primarily of four steps:
1. Examining the characteristics of the candidate wells that will be drilled during the year. Conventional wells that do not require hydraulic fracturing and well stimulation can be cleared of drilling fluids and connected to a sales line relatively quickly with minimal gas venting or flaring involved, therefore the use of REC technology for these applications is usually not economically justifiable. Wells that involve energized fracturing using inert gases require special considerations because the initial produced gas would not meet pipeline specifications due to the inert gas content. However, as the amount of inert gas decreases, the quality of the gas will likely meet pipeline specifications and may be economically worthwhile to capture through REC.
2. Determining the costs. The cost for green completions will depend on the need for special equipment (compressors, on-site dehydrators, membrane separator, etc.) which is tied to the characteristics of the well. Costs will also vary depending on whether operators choose to use third-party contractors to perform the RECs or whether operators choose to invest in their own portable REC equipment and operate it themselves. When using a third party to perform RECs, it is most cost effective to integrate the schedule of completions with the annual drilling program. To ensure profitability of using green completion equipment, it is important for it to move efficiently from site to site within the field so that there is little down time when paying for equipment rental and labor.
3. Estimating savings. Savings will be dependent on the amount of gas recovered, the market price of natural gas and the amount of condensate that can be recovered in the REC three-phase separator. The amount of gas and condensate recovered will vary from well to well depending on the reservoir and operational characteristics of the drilling and completion.
4. Evaluating the economics of the completion program by weighing the economic benefits and expenses to determine whether this is a viable option. Regulatory considerations should also be made as green completions have been required in some areas.

Decision drivers

Technical: Reservoir pressure: reservoir pressure must be higher than the back pressure in the REC or the gathering system. The maximum rated pressure of the system is dependent on the type of system and the individual vendor equipment. Based on one vendor (Weatherford) the maximum rated pressure would be depend upon the weakest link in the system components – which would be the process tank at 600 psi [12]. The maximum pressure of the sand trap for the Weatherford system is 10,000 psi. This information is specific to this system, and Vvendors should be contacted to verify individual applications prior to leasing or purchasing equipment. In low pressure reservoirs, RECs are often carried out with the aid of compressors for gas lift. Gas lift involves using gas from the sales line that is boosted with a compressor and routed down the well casing to push the frac fluids up the wellbore.
Compression to sales line: When the reservoir fluids have enough pressure to reach the wellhead but the gas recovered from the REC results in lower pressure than the sales line, a compressor engine may be required to boost flowback gas into the sales line. This technique is still experimental because of the difficulty operating a compressor on widely fluctuating flowback rate. Coal bed methane completion is an example where additional compression might be required
Inert gas stimulated wells: Some wells use inert gas (carbon dioxide and nitrogen) to energize the hydraulic fracturing process. The gas initially produced from these wells may have to be flared until the gas meets pipeline specifications. Alternatively, a portable acid gas membrane separator may be used to recover methane rich gas from the inert-heavy gas stream. As the flow rate of fluids drops and methane rich gas is encountered, backflow may be then switched over to the REC equipment so that the gas is captured.
Operational: Connection to sales line: it is necessary that a piping system or gathering lines are in proximity to the well completion location so that captured gas during flowback can enter the sales line. This is why generally exploratory wells or delineation wells are not suitable for RECs since they are drilled in areas where there would not be a readily available pipeline system in place
Risk of blowouts: stable recovery of gas is essential. Green completions are not inherently suitable to violent releases of pressure such as blowouts. Pressure of the gas must not exceed the rating of the sand trap or separator vessels
Commercial: REC technology is commercially available and can be rented through service providers or purchased. In a large basin with high drilling activity levels it may be economic for an operator to purchase its own REC portable skid. Most producers may prefer contracting a third party service to perform completions
Environmental: RECs help reduce methane, criteria pollutants and hazardous air pollutant emissions. Produced water and stimulation fluids from green completions can be recycled for future frac jobs as water is recovered in the three-phase separator [4]. Green completions also eliminate emissions, noise and public complaints associated with flaring practices. Some jurisdictions have begun requiring green completions as emissions reduction mechanisms
Economic rule-of-thumb: Payback time has been reported to be as little as 3 months by natural gas operators, but tends to be around one year on average [1]. Generally, lengthy completions, such as those following hydraulic fracturing, imply a significant amount of gas that could potentially be recovered and sold for additional revenue to justify the additional cost of a REC. When assessing the economic viability of green completions, gas prices influence the decision making process, as they will impact the return on investment and the payback time for purchases of REC equipment, as well as determine the value of natural gas savings. The amount of condensate recovered and the sales price will also affect profitability.

Additional comments

Ultimately, a key decision driver for performing green completions may be government regulations. Recent U.S. federal regulations like NSPS Subpart OOOO will require RECs for hydraulically-fractured natural gas wells that take place from 2015 onward. Exceptions are made in the federal regulations for exploratory or delineation wells. The States of Wyoming and Colorado have regulations requiring the implementation of “flareless completions”. Operators of new wells in this region are required to complete wells without flaring or venting. These completions have reduced flaring by 70 to 90 percent [Reference 1].

The advantages and shortcomings [References 4,5,6] of green completion technology are summarized below:

Advantages:

  • Reduce greenhouse gas emissions and other criteria pollutants
  • Selling captured gas instead of venting / flaring
  • No visible flares, thus less conflict with operations near populated areas
  • Improved overall safety at the well site
  • Water and stimulation fluids can be recovered for re-use in other fracking jobs; hence reduced water disposal costs.
  • Offers potential compliance pathway for future regulation

Disadvantages:

  •  Must have an operational gathering system in place
  •  Requires specialized equipment
  •  Requires adequate reservoir pressure
  •  Incremental cost of “green” completion unit - approximately 30% more than a conventional well completion unit
  •  Profitability depends on value of gas sold – profit margin may be small

Alternative technologies

Alternative technologies to capture produced gas during well cleanup other than RECs are not readily available, however, the oil and gas industry has been working on methods to make well completions more efficient, in terms of decreasing the duration of the operations, and also the amount of gas that is vented or flared during this lengthy procedure. An example of these efforts is Marathon Oil’s completion technology EXcape® or Casing-Conveyed Perforating System (CCP) [Ref 7], a new method for completing natural gas wells that consists of a different casing design that allow well cleanup to occur much faster; CCP allows the completion team to perforate and stimulate all intervals in a single day. According to reviews, completions performed with CCP technology are more cost effective due to shorter operations, while simultaneously reducing methane emissions and improving safety conditions. Marathon Oil estimates a reduction in venting anywhere from 2,750 MCF to 7,850 MCF per well - gas that ends up in sales. This is accomplished by the multi-stage completion design of the casing that has perforating guns and isolation devices externally mounted to the casing, enabling the performance of simultaneous and quicker perforations of each completion stage [Ref 8].

Operational issues/risks

There is a reduction of safety risks at the well site by using green well completions, associated with the removal of flares and reduction of vented emissions.

However, there may be other operational and safety risks that could be encountered during REC operations [Ref 9]:

  • Wellbore damage by fluids pumped down hole can diminish production.
  • Flowing fluids to REC equipment can result in decreased flowback rates due to high back pressure from the piping system (versus no back pressure when venting is performed).
  • The piping configuration leading to the sand traps is critical as the abrasion from high velocity water and sand can erode a hole in steel pipe elbows, creating a “washout” of the pipe and releasing hydrocarbon liquids, water and gas into the well pad. That is why it is also recommended to use plug catchers to catch large solids that could damage separation equipment. Pipe fittings and elbows should be reinforced with high strength metal.
  • REC operator should check location frequently (every 1 to 2 hours) during the well completion operation to identify leaks before they become washouts.
  • Pressure of the gas must not exceed the rating of the sand trap or separator vessels. REC equipment not suitable to handle blowouts.

Opportunities/business case

Natural Gas Star Partners have reported recovering 2% to 89% (average of 53%) of total gas produced during well completions and workovers from high-pressure wells [Ref. 10]

An estimated 500 to 2,000 MCF/day/well of natural gas can be recovered during a well cleanup. The amount of gas recovered is therefore a function of the duration (days) of the flowback period. An average green completion may last about nine days, which would translate in gas savings from 4,000 to 18,000 MCF/well. Delivering this amount of gas to the sales line can produce revenues between $28,000 to $126,000 based on gas price of $7/MCF. Revenues from captured gas sales will vary according to the market price of natural gas; however even at low gas prices of $3/MCF, it is estimated that it would still be economical to perform green completions [Ref 1].

In addition, 1 to 580 barrels of condensate may be recovered from each cleanup depending on reservoir conditions. This could translate into upwards of $30,000 additional revenue from condensate sales at $50/barrel (Natural Gas Star, 2010). The benefits of using green completions will vary considerably among individual wells and reservoirs, but can often be economically favorable. The following benefits are identified:

  • Sales revenue from natural gas and gas liquids captured during the green completion may be sold.
  • Lower methane emissions
  • Lower safety risks at well site
  • Improved relations with government agencies and public neighbors
  • Reduced cost for disposal of fracking liquids (as these can be recycled).

Industry case studies

Experience for Noble Energy in Ellis County, Oklahoma [Ref. 1]

  • Noble Energy implemented RECs on 10 wells using inert gas energized fracturing.
  • Employed membrane separation in which the permeate was a CO2 rich stream that was vented and the residue was primarily hydrocarbons which were recovered.
  • Total of nine wells were tested, eight of which the REC system processed flowbacks from a single well completion, and one of which was a commingled stream from two well flowbacks
  • Total cost of $325,000 including equipment and rental labor
  • Total gas savings of approximately 175 MMcf.
  • Estimated net profits were $340,000
  • The project resulted in the reduction of methane emissions and yielded economic revenues from selling gas that would have otherwise been flared. Commodity prices and the practicality of combining the flowback gas from different wells will be important in determining future use. Commingling the flowback gas can double the gas savings for the same rental and set-up costs.

Experience of BP in Green River Basin [Ref. 10]

  • Implemented RECs in the Green River Basin of Wyoming in 2002.
  • RECs were performed on 106 wells, which consisted of high and low pressure wells.
    BP reported a capital investment of about $500,000 per skid on portable three-phase separators, sand traps, and tanks in the Rocky Mountain Region.
  • Average 3,300 Mcf of natural gas sold versus vented per well. Well pressure varies from reservoir to reservoir, thus affecting the rate of production. Conservative net value of gas captured is $20,000 per well.
  • Total natural gas recovered about 350 million cubic feet per year (MMcf/year) in that year.
  • Total of 6,700 barrels of condensate recovered per year total for 106 wells
  • This Natural Gas Star partner reports a total of 4.17 Bcf of gas and more than 53,000 barrels of condensate recovered and sold rather than flared through the end of 2005. This is a combination of activities in the Wamsutter and Jonah/Pinedale fields.

Experience from Williams Corporation [Ref 11]

  • Williams Corp. performed RECs in the Williams Fork Formation (Piceance Basin) – a low permeability, tight, lenticular sandstone.]
  • BRECO flowback skids were used to separate sand, water and gas during initial flowback (Figure 3). The flowback skids reside on a typical 4-well pad for 32 days.

Figure 3.  BRECO Reduced Emissions Completions Skid (Source: Williams. Natural Gas Star. 2006)

  • Flow pressures range from 1,500 to 2,500 psi; these are high pressure wells, no requirement for gas lift.
  • Operator reported average gas volume recovered per flowback was 23 MMCF.
  • The revenue per flowback was $139,941, based on gas prices of approximately $6/MCF.
  • Other economic characteristics of this case study are shown in Table 1.

 

Table 1.  Green Completion Economics for Williams REC Experience (Source: Williams. Natural Gas Star. 2006)

Case studies presented here show that variations in the operational and reservoir conditions will have a major impact in the level of profitability of each REC implementation project. High maintenance wells, such as those requiring inert gas stimulation (like in Noble Energy’s experience) appear to have a lower revenue per completion (~$34,000) than high pressure wells requiring a simpler REC configuration, such as the case for Williams, where revenue was as high as $129,510 per completion. Moreover, the effective usage of a REC equipment in multi well pads where flowbacks from various wells can be combined into a single skid set-up seems to be a key way to reduce costs. The usage of the Breco skid for four wells in the Williams experience, as wells as the commingling of two flowback streams in the Noble Energy case study appears to suggest this.


References:

  1. EPA Natural Gas Star, 2011. “Reduced Emissions Completions for Hydraulically Fractured Natural Gas Wells. Lessons Learned from Natural Gas Star Partners.
  2. IPS, 2005. “Green Flowback Process.” Producers Technology Transfer Workshop. October, 26.
  3. Colorado Oil and Gas Conservation Commission (COGCC), 2008. “Proposed rules for Green Completions.” June 27.
  4. Anadarko Petroleum Corp, 2008. “Reduced Emission Completions in DJ Basin and Buttes and Natural Buttes.” Producers Technology Transfer Workshop. May 1. Rock Springs, WY.
  5. BP America, 2008. “Reduced Emission (Green) Completion in Low Energy Reservoirs.” November 12.
  6. Marathon Oil and EPA Natural Gas STAR Program, 2005. “Reduced Emission Completions (Green Completions).” Lessons Learned from Natural Gas Star. October, 26.
  7. EPA Natural Gas Star, 2007a. Partner Update. Technology Spotlight: Marathon Oil Company Targets Emissions Reduction Opportunities during Well Completions. Summer
  8. Smart Completions, 2013. Technology Distributor. Excape Conveyed Perforating Brochure
  9. EPA Natural Gas Star, 2007b. “Reducing Methane Emissions During Completion Operations.” Production Technology Transfer Workshop. September 11. Glenwood Springs, Colorado
  10. EPA Natural Gas Star, 2010. “Reducing Methane Emissions from Production Wells: Reduced Emission Completions.” Producers Technology Transfer Workshop. May 11
  11. EPA Natural Gas Star, 2006. “Williams Experience in Methane Emissions Mitigation.” Producers and Processors Technology Transfer Workshop. May 11. Rock Springs, WY