Rosneft: Improving Well Completions – Sealing Wellbore Leakage

B. A. Erka (Doctor of Science), A. V. Khabarov, N. A. Gerasimenko
Tyumen Petroleum Research Center

Because of the growing volume of hard-to-recover reserves in the portfolios of operating companies, and due to drilling deeper wells in more complex geology (development of oil rims) we are facing more and more reliability problems during well design and a need to reduce wellbore leakage. Wellbore leakage around the production liner may have a negative impact on the oil production process due to the risk of a considerable increase in the gas-oil ratio (GOR) or in the volumes of water production. The channels that are formed, in the set cement, facilitate fluid flow in the casing string annulus from the gas cap into the borehole, which, in turn, leads to reduction in oil rates. The challenge in identifying cross flows is that some of them are concealed, and a high GOR during oil production may occur for other reasons as well. Often, the low quality of liner cementation is caused by a small annular clearance between the production casing liner and the borehole wall and the inability to ensure a homogeneous cement sheath around the production liner, which weakens the holding capacity of the set cement.

Field experience demonstrates that during the first 10 years of the wells service life, about 75% of recoverable reserves are lost, between 10 and 20 years, 25-50% is lost, and during 30 years of well operation only 10-15% of reserves is lost. Therefore, the reliable isolation of the casing string annulus and increasing its durability is of key importance [1].

Main Factors Controlling Well Casing Process 

There are many factors that control the well cementation process, including natural factors (temperature and pressure conditions, tectonic faults, reservoir poroperm properties, etc.), technical-technological (state of the wellbore and well design, cementing materials, process parameters), and organisational factors (personnel qualification level, etc.).

The main problems occurring while cementing wells are:

» Low top of cement

» Crossflows between beds

» Fluid kicks

» Removing filter cake from the wellbore

» Inability to run casing strings to bottom

While the low top of cement or inability to run casings to bottom are generally caused by non-compliance with the process regulation when cementing, the fluid migration, fluid kicks, and low quality of wellbore cleanout require changes in the well cementing technology and the use of other cementing materials, as well as improvement in well logging quality.

There are many methods, process measures, and technical devices that, when used in combination, make it possible to eliminate annular gas kicks in wells and restore the integrity of the annulus space. Wide domestic and international experience has been gained on the prevention of gas migration [2]. The developed measures for the prevention and elimination of fluid migration include both the improvement of well drilling and operation processes and development of new tools and techniques for elimination of behind-casing gas migration.

The existing technologies to prevent wellbore leakage are mainly aimed at better cementing quality that ensures a more complete and uniform removal of drilling fluid, removal of filter cake from the hole wall, development of new cement mixes, and application of annular packers. To eliminate the already existing gas flow pathways, corrective pressure cementing is used as well as injection of various sealing compounds, switching the well to packer operation, metal axially fluted pipes, clads, etc.

Main Methods to Eliminate Behind-casing Gas Leaking 

Isolating gas leakages in oil wells is a serious challenge.
The operation of wells with high free gas content significantly reduces the recovery of oil reserves and the efficiency of pumping equipment.

The domestic experience showed that high GOR is due to the following reasons [1]:

» Incorrect determination of the gas-oil contact or water-oil contact in about 38% of wells

» In 29% of the cases, it is due to cement loss and, consequently, low top of cement

» 15-25% of the cases are due to fluid migration

» 5% due to fluid kicks

» 5-13% due to inability to run casing strings to bottom.

At present, there are a few key potential solutions to the gas leaking problem:

Mechanical isolation when running packer equipment. This method is quite reliable, it is characterized by simple installation and a comparatively low cost. The average rate of success of the mechanical method of gas leaking isolation is more than 90%. However, along with the benefits, this method has a number of disadvantages, such as:

» Lack of methods to determine the packer leak tightness

» High risk of inability to release the packer in case the elements of pumping equipment fall down the hole

» Increase in the cost of subsequent well servicing

» Severe corrosive wear of the internal surface of the string also reduces the efficiency of this method.

The conventional methods of cement squeeze jobs [2], e.g. injection of various compounds, demonstrated a low rate of success of such jobs at significantly higher costs versus using the packer equipment.

The efficiency of the cement squeeze jobs, to a large extent, depends on the information about the causes and the location of the crossflow source, while the cement squeeze configurations and techniques are in fact always the same and may differ in the points of cement entry zone into the casing string annulus. The main disadvantages of cement squeeze jobs are:

» High cost of the jobs

» Need to kill the well, which results in lower permeability of the near-wellbore zone

» Complexity of the job.

Re-cementing the casing string annulus is expensive, and amounts to about 15-20% of the entire well cost.

When developing oil rims, the most uniform development of oil reserves may be ensured by drilling horizontal wells which intersect the layers of the pay formation at the estimated distances from the WOC and GOC. While operating such deposits, annulus gas leakages often occur, which results in a high GOR during production.

The following well design is usually used when developing an oil rim: a conductor pipe, a surface casing, a 168/178mm production casing, a shoe that is set on the top of pay zone, and a 114-mm slotted liner with upper blind pipes which is run to the pay zone followed by collar cementing of the blind pipes (Fig. 1).

The main problem during cementing of the upper part of the liner is a small annular clearance between the production casing liner and the borehole wall. The outside diameter of the liner coupling is 127 mm, the open hole diameter is 143 mm, which leaves an 8mm clearance. A relatively small width of the cement sheath in a gas-saturated interval will very much likely lead to behind-casing crossflows. Cement bond log data does not provide a clear picture on the cementing quality.

Recommendations to Minimize Risks of Crossflows

To minimise the risks of crossflows, there are a few options for improving the well design reliability.

1. Apply reaming tools when drilling horizontal wells in order to increase the hole diameter from 143 mm to 156 mm while retaining the current liner diameter of 114 mm. Application of reamers will help ensure higher quality cementing of a small-diameter casing string (liner through increasing the area of the cement sheath, but this technology has some substantial disadvantages such as drilling tool sticking when reaming the hole with special tools.

2. Use expanding cement slurry to improve cement-to-casing bond and cement-to-wall bond. A substantial disadvantage of such slurries is their high cost and an insecure solid
cement sheath.

3. Use packers to considerably reduce the risk of wellbore leakage. Their main disadvantage is the need to have a non-permeable tight seal in the point of their placement, because otherwise circulation in the casing string annulus will occur in the rock behind the packer.

Having reviewed a large number of options for improving well design reliability, we suggest to test a combined option to reduce the risks of gas breaking through into the wellbore:

» Adjust the well profile by running the liner below the OWC followed by its return to the oil zone and cement the collar. We expect that this profile will help substantially reduce the risks of gas breakthrough thanks to a “hydraulic seal” (Fig. 2). High complexity of drilling is one of the main disadvantage of such hole-making.

» Include a straddle packer with a rubber oil-swelling element in the slotted liner assembly. This will allow to block off the parts of the horizontal section with gas breakthroughs. One packer splitting the horizontal area into two parts will be enough to increase cumulative oil produced by a well.

It is unlikely that crossflows will be completely eliminated by using only one of the above methods. To reduce the risks of behind-casing fluid migration, it is recommended to apply several appropriate methods simultaneously.

To reduce the probability of gas breakthrough behind the production liner, the well profile needs to be adjusted by adding swellable packers to the liner assembly. Such well completion system will help considerably minimise the risks of gas breakthrough during well operation without a significant increase in the drilling costs.

Based on the above, to minimise the risks, the well design and profile should be selected wisely at the designing stage, as this will help prevent early fluid migration from the upper zones and, consequently, costly cement squeeze jobs.

References:

1. A. I. Bulatov, P. P. Makarenko, Y. M. Proselkov, Washing and Cementing Drilling Muds. Nedra, 1999, page 424.

2. B. Baily, J. Tyrie, J. Ephick, Water control, Oilfield Review Vol. 3, 2001, page 25.