For the past several years shale exploration has driven America toward energy independence but not without challenges. The cost of drilling and completing horizontal wells continues to drive industry experts and engineers to seek more economical ways to exploit these reservoirs.

New drilling technology allows the wells to be drilled much faster. Well pad drilling and zipper fracks are gaining popularity with many producers as hydraulic fracturing drives the cost of shale oil production.

While most producers put an emphasis on exploration, many also are now focused on artificial lift methods. This is due to the decline curves of wells before artificial lift systems are required. With these decline curves becoming more prevalent in the Eagle Ford, Permian, Bakken and other shale plays, the number of wells produced using artificial lift are growing at an exponential rate.

Background

Today the largest amount of production is said to come from electrical submersible pumps (ESPs). However, the largest number of wells are completed using reciprocating rod lift (RRL) or sucker rod pumps (SRPs).

Engineers are challenged with optimizing production over the life of the well and frequently conduct a front-end load engineering study to predict the life of the well’s performance. Having this modeling in place along with a comprehensive understanding of the long-term effects of different completions and artificial lift methods can drive down the overall cost to produce a well and drive up the production, positively impacting a company’s return on investment.

Today’s shale oil production presents many new challenges as the industry drills faster and uses frack sand in hydraulic fracturing. Many forms of artificial lift are not designed to handle solids produced from the wellbore, albeit injected during fracturing. In heavy oil produced in Canada, Venezuela, Colombia and California, progressive cavity pumps (PCP) are the most commonly used form of artificial lift. Fundamentally this is an auger-based design with a rotor and stator designed to produce solids and high-viscosity oil. Producers are trying different forms of artificial lift to optimize production.

Because the industry is now more efficient in shale oil, it has deep deviated wells producing side-loading conditions both in the vertical and horizontal sections of the well along with sand slugging sometimes associated with well kicking post-flowback.

The industry is seeing the meantime between failures (MTBF) decreasing due to well deviations. One common problem in deep deviated wells is side-loading conditions, where rod and tubing wear are experiencing side loads in excess of 150 psi, resulting in premature failure either in parted rods or holes in the tubing string. A common failure in conventional sucker rodstrings is due to the mechanical makeup of conventional sucker rods. Mechanical failures have been reduced due to the implementation of best practices, but operators now have side-loading conditions coupled with sand slugging. Most producers are challenged in seeking ways to increase their MTBF.

Front-end load engineering study

One process many producers are practicing is a front-end load engineering study, where the life of the well is analyzed as it relates to the capex and opex invested over the course of the well’s productive life using products and equipment that maximize productivity at each phase of its life, beginning with the initial completion until post-artificial lift.

There have been technological advances made by the producer and service companies over the last 25 years still being used today that are conducive to producing shale oil, such as ESPs, RRL and gas lift, among others. There remains a keen focus on refining technologies such as the linear pumpjack and advancements in elastomers used in PCPs or high-temperature wear-resistance coatings used in production tubing and drillpipe.

Since SRP remains the most common method for shale oil in deep deviated wells (with more than 350,000 wells using SRPs in the U.S. alone), the industry is focused on increasing the MTBF caused by side-loading, misalignment of pumpjack and/or the pumpjack walking and bottomhole pump failure due to producing solids and gas migration.

Additionally, operators are experiencing difficulties when trying to set conventional tubing anchors or packers. These, among others, are common problems associated with deep deviated wells.

CR

Coiled rod (CR) has been around since the early 1970s, originally designed for SRP wells along the Rockies due to the fault lines. Later adapted by PCP in the early 1980s and the most common method used with PCPs today, CR is becoming a hot topic among producers as a viable method used with SRP wells.

Challenges such as corrosion remain with this technology. However, in wells where corrosion is not an issue, CR can reduce side loads and friction significantly.

Of course, one of the major challenges for most producers is having service equipment available on the ground when a well goes down. It is highly specialized, similar to coiled tubing but on a smaller scale. It is clear from speaking with several of the majors and independents who have expressed growing interest in CR that the industry is moving in that direction.

CR disperses the side-loading effect that is typical of a conventional sucker rod coupling, usually 4 in. in length, bearing the entire load over the entire length of deviation. Inhibitors, lubricants and surfactants are commonly used to reduce paraffin and/or scale buildup, which typically occur in or around the rod and tubing couplings.

Some of the benefits of using CR are reduced friction and paraffin, resulting in increased production since there are no couplings. Additionally, the rodstring can be rotated on a regular basis so that the contact area is exposed to the chemical treatment process. CR is not the solution to all deviated wells, such as wells with corrosion (although there have been advancements made to coat the rodstring using polymers and nanocoatings to address this), but CR can contribute to reducing MTBF.

Tubing anchors and stuffing boxes

Other advancements such as the quarter-turn tubing anchors and self-aligning stuffing boxes are making progress. Both of these technologies are interesting as they gain successes with their install base, particularly due to side loading and misalignment of the pumpjack units.

The 1/4-turn tension tubing anchor catcher is a nice option to the packer. Many operators are removing the elements of the packer to handle gas migration and solids. Setting a multiple-turn packer or tubing anchor can be challenging when set at 3,048 m (10,000 ft) with side loads in excess of 150 lb. In some cases even the most experienced workover superintendents find it challenging when setting these tools in deep deviated wells.

This is where a ¼-turn tension tubing anchor could save a company time and money. Another form of anchor gaining traction is the hydraulic anchor—although not a “catcher,” it can provide operators a solution when the tubing cannot be turned at all.

One common problem often mentioned is misalignment or walking of the pumpjack. This is where the pivot stroker-style stuffing box can provide a nice option to the conventional stuffing box. The top of the box pivots up to 1.5 degrees to help eliminate misalignment caused by the polished rod or pumping unit.

These are just a few of the technologies available on the market today to address problems associated with deep deviated wells. These technologies are not a “one fix all” but rather solutions to specific problems with deep deviated wells. CR, tubing anchor catchers and self-aligning stuffing boxes incorporate old and new technologies that assist with these wells and positively increase the MTBF.

To get the most out of each artificial lift system, each well should be engineered individually based on its own characteristics.