Wellbore pressure boosting enhances recovery from natural gas wells

Well potential, when measured against reservoir pressure with central gas compression, shows the effect of introducing downhole gas compression.

Wellbore flow boosters have eluded the industry for many reasons. To start with, gas compressors need to be driven at speeds in excess of that possible with oil-filled electrical motors, which would otherwise suffer from unacceptable levels of churning loss. Achieving appropriate speeds with oil-filled motors requires gearing and resolution of attendant high-speed shaft sealing issues. High-speed hydraulic drives can be ruled out because of their need for high-pressure, high-speed shaft seals resulting from the high static head from the wellhead to the downhole compressor.

Another option is to provide drive by means of a gas expander powered by high-pressure surface-supplied gas. Drive gas must be co-mingled with the produced gas and returned to the surface. Since this option greatly increases the flow burden in the well, it is inefficient and cannot produce the required net production flow rates.

The existence of compressor, bearing, and permanent magnet motor drive technologies raises the opportunity for a practical solution for wellbore compression. The value of these technologies for enhancing recovery from natural gas wells is primarily to:

• Guide the operator toward the appropriate application of downhole gas compression (DGC) by showing a number of field development scenarios
• Present a feasible concept that has been subjected to an expert peer review
• Describe the forward development program to bring this game changing technology to the marketplace.

Compression advantages

To understand why wellbore compression offers advantages we need to recognize that two processes are at work.

DGC increases the density of gas in the wellbore. For the same mass flow rate, the velocity decreases, which reduces frictional losses in the wellbore. Noting that tubing friction loss is proportional to the square of the velocity, a modest increase in tubing pressure can result in a significant increase in tubing transport capacity. DGC can therefore deliver significantly more gas than is achievable using central gas compression (CGC) alone.

Second, placing the compressor at the bottom of the well reduces the flowing bottom hole pressure, increasing drawdown from the reservoir, which in itself accelerates production.

Suction pressures are higher downhole, so only modest pressure ratios (up to approximately 2:1) are required to produce a significant absolute pressure rise. A similar pressure rise at surface would require much higher pressure ratios from central gas compression. DGC's ability to reduce flowing bottom-hole pressure facilitates the lowest abandonment pressure, maximizing reserves that can be recovered from the reservoir.

A comparison of well potential for a North Sea gas field illustrates the incremental production rate and recovery possible by adding DGC to a field that already operates with central compression. When well potential is measured against reservoir pressure with CGC, it is evident that introducing DGC markedly accelerates recovery, particularly at higher reservoir pressures when the static head is highest, and significantly increases ultimate recovery.

It is worth noting that because of their distance from the reservoir, both CGC and wellhead gas compression (WGC) exacerbate the suction tubing friction losses, limiting production acceleration and their economic benefit. Generally, accelerating production is economically more attractive than extending the tail-end production, although bringing tail-end production forward does offer clear economic benefits.

Increased reservoir drawdown and in-creased tubing performance can also be shown by plotting the inflow performance curve from a reservoir against the production tubing vertical lift performance curve for cases with and without wellbore compression. This analysis assumes an installed power of 670 hp (0.5 MW) per well. The basic casing scheme for the wells was 9 5/8 in. stepping down to 7 in., closer to the production perforations.

The reference field was already in prod-uction decline and had central compression installed.

It was found that by applying DGC an immediate increase in production of 32-41% at the time of installation could be achieved, based on a modest compression ratio of only 1.13:1 at the downhole compressor.

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Well screening

The scope for compression for increasing the well potential and ultimate recovery can be derived from two factors – reservoir drawdown and tubing friction. Where the pressure drop in the tubing is friction-dominated, adding compression allows larger mass flow rates to be achieved for a similar pressure drop, as is the case when production is tubing-constrained because the flow has reached critical velocity at the wellhead. Compressing the flow near the reservoir end-face reduces the bottom hole pressure for a given tubing head pressure, allowing inflow to the well from the reservoir to increase.

Field Statistics
Reservoir pressure: 870 psi
Product temperature: 200º F (94º C)
Wellhead pressure: 690 psi
Depth (TVD): 9,100 ft (2,800 m)
Liquid to gas ratio: 9 bbl/MMscf
Reservoir depletion rate: 0.25 psi/bscf
Gas mol weight: 19.8 kg/kmol

The maximum well potential is achieved when the bottom pressure reduces to zero (i.e., at its absolute open flow (AOF) potential). There is scope for accelerated recovery using downhole compression when the tubing flow is friction-dominated. Downhole compression is also successful in prolific reservoirs with relatively low drawdown.

Candidates can be evaluated based on drawdown and flow characteristics.

The first combination is low drawdown and friction-dominated flow. At relatively low drawdown, the well potential is much less than the AOF limit, so there is scope for a significant increase in production with gas compression applied. The mass flow rate is tubing constrained since flow is near critical velocity in relatively small diameter tubing. An increase in mass flow can only be achieved through downhole compression. Neither wellhead compression nor additional CGC is effective in this scenario.

The second combination is low drawdown and gravity-dominated flow. A significant increase in production is possible in this case too. With gravity-dominated tubing flow, however, there is no distinction between wellhead and downhole compression. Both lead to an increase in ultimate recovery.

The third combination is high drawdown with friction-dominated flow. At high reservoir drawdown pressures, there is less scope to produce at higher rates because the well flow rate is close to its AOF potential. Any increase in well potential would be small. Because the flow is friction-dominated, wellhead compression would also be ineffective.

The final combination is high drawdown with gravity-dominated flow. Since the well flow rate is close to its AOF potential, the scope for acceleration is limited. There is, however, some scope for increased ultimate recovery using either wellhead or downhole compression.

Screening for candidate fields

There are a number of likely situations where downhole compression technology can be expected to create value.

The technology is best applied in the later stages of plateau production, possibly still from freely flowing reservoirs, where the tubing represents the most significant source of pressure loss in the overall production system.

When open choke production has started, downhole compression technology can extend plateau production. The technology also should typically be applied in conjunction with central compression, but could be a viable alternative to that early on.

High-pressure/high-temperature fields offer little compression potential because of the reduced temperature window between the bottom-hole temperature (BHT) and the current design limits of downhole electronics. This is particularly true of wells where the BHT is below 270° F (120° C).

Based solely on economic considerations, the application of DGC is likely to be cost effective on wells where the incremental production is expected to be 0.5-1 MMcf/d or greater for offshore well locations and 100,000-200,000 cu ft/d for onshore field locations.

Onshore and offshore fields are both likely to present favorable economics. For subsea wells, higher workover costs reduce the economic benefit.

DGC can offer proportionately greater accelerated production if it is applied during early field life than is achievable if it is applied later in field life. DGC could offer an enabling technology, allowing the development of otherwise sub-economic or backed-out fields.

While candidate fields can be identified from one or more of the situations listed, many other factors, including gas sales price, reservoir characteristics, and the availability of suitable facilities influence whether the application of DGC is appropriate to a given field.

Design concept

Combining proven technologies from other industrial sectors with some key innovations could provide operators with new functionality for enhancing gas production. Innovations allow these technologies to operate in the hostile downhole environment. Through the combination of patented gas bearings and a gas filled permanent magnet motor, a new direct drive system is now capable of achieving the rotational speeds required for an efficient axial turbo-compressor. The drive system has no contacting surfaces in operation and eliminates the need for gearboxes, shaft seals, liquid lubrication systems, and couplings. In short, all of the vulnerable, wearing components typically used in ESP technology are no longer concerns.

The key enabling base technologies of gas bearings, permanent magnet motors, and their accompanying motor controllers have been in reliable operation with Corac for a number of years.

One such system built for the industrial oil-free compressed air market, contains multiple compressor spools, each rated at 70-200 hp (50-150 kW). The target installed compression power per well for DGC was taken to be 670 hp (0.5 MW). A modular approach that combines a number of compressor stages was necessary to achieve this level of installed power.

The three principal methods of tubing (conveyed, coiled tubing, and wireline) were assessed in reviewing deployment and completion options. The key parameter driving the DGC's design is the need to maximize machine diameter. Maximizing diameter achieves the greatest modular power rating and the greatest installable compression power.

Integrating the machine with the tubing string can occupy the full bore of the well casing. As neither coiled tubing nor wireline offers this possibility, a jointed tubing completion is seen as the most appropriate for this technology.

Through the combination of patented gas bearings and a gas filled permanent magnet motor, a new direct drive system is now capable of achieving the rotational speeds required for an efficient axial turbo-compressor.

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A comprehensive failure mode and effect analysis (FMEA) was also completed for the concept, as was a peer review with discipline and asset group technical specialists from the sponsoring operator.

While recognizing there are a number of technical challenges to be resolved, no "show stoppers" were found, making the concept technically feasible. Further, a mean time between failure (MTBF) of 3-5 years at entry into production service was considered achievable due largely to the simplicity of design.

Proof-of-concept has been established based upon proven technologies from other industrial sectors coupled with key innovative ideas to enable the design concept to operate in the hostile downhole environment.

Some technical challenges remain to be addressed in the next development phase, principally in the composition of well liquids and fines, the application of gas bearing technology to the downhole environment, and the development of downhole electronics enabling the maximum installable electrical power.

Prototype qualification

Having established proof-of-concept, a forward engineering program has been outlined with a number of operators. Direct participation by operators is considered crucial to its successful completion, ensuring alignment of engineering objectives with those of the end-users and access to fields for qualification trials of the prototypes.

The engineering program will focus on several key areas, leading to a downhole prototype trial:

• Bearing development for use in untreated hydrocarbon gas
• Bearing lubrication gas off-take and material selection
• Downhole power electronics/power transmission
• Compressor performance with increased liquid loading
• Product range development.

With the successful completion of technology verification phase, development can progress with a conventional product engineering design, manufacture, and qualification test program.

This is a summary of the OTC 16372 paper.