Operators tapping into the sizeable oil and gas resources in the U.S. Arctic—up to 23 Bbbl of recoverable oil and 3 Tcm (108 Tcf) of natural gas by some estimates—have to navigate a complex set of challenges. These include intrinsically high E&P costs related to the remoteness of the region, extremely low-temperature operating conditions, and stringent well containment and emergency response requirements mandated by government regulatory bodies.

This was the environment an operator faced in 2010 when attempting to complete an offshore Alaska well with an artificial lift option that would boost declining production rates and also restore production to some wells that were closed due to completion problems. The operator considered a number of artificial lift solutions but had to carefully weigh their suitability against factors such as the production potential of the well and anticipated installation and operating costs.

Exploring alternatives
Sucker-rod pumping, the most widely used artificial lift method in onshore operations, offers low upfront installation costs and a wealth of well-established operational knowledge. In this offshore Alaskan well, however, rod pumping would have been difficult to execute given the small deck space available on the platform. The risks of frequent and costly workovers to replace worn-out rods also proved too great.

The operator considered gas lift, but the lack of adequate and long-term volumes of gas supplied from the well would have made this a relatively short-lived solution. Gas lift also requires large and cost-intensive gas compressors at the surface that take up considerable space on the platform and add to maintenance costs.

Electric submersible pumps (ESPs) represented another option. While ESPs have been successfully deployed in offshore wells throughout the world, their low tolerance for sand and need for workovers to make repairs made them a prohibitively expensive option in this particular application.

The optimal lift solution for this well, and one that the operator had successfully used in the past, came in the form of hydraulic jet pumping.

Jet pumping basics
In a jet pump lifting system, a power fluid—typically oil or water produced from the reservoir—is pressurized and pumped down the well via a surface pump. The power fluid travels through the downhole jet pump, which is equipped with a nozzle, throat and diffuser. Power fluid flows through this nozzle to create a low-pressure jet core at the end of the nozzle. The low pressure draws reservoir fluid into the pump intake, and the jet core drags reservoir fluids into the throat or “mixing tube,” where the two streams of fluid combine and momentum transfer takes place. The mixed homogenous flow then transfers to the pump diffuser, where static pressure is increased to raise the combined fluids to the surface.

With no moving parts and a compact, durable design, jet pumps have a reputation for reliability and long runlives. Pumps are deployed without a rig simply by using pressurized fluid to set the pump downhole. Redirecting the flow of the power fluid brings the jet pump back up the wellbore for easy retrieval. Recovery of a gas-lift system or ESP typically requires a workover rig.

A common drawback cited with jet pumps is their relative energy inefficiency. It is true that jet pumps commonly run at 20% to 30% efficiency—which means that only 20% to 30% of the total power supplied goes to lifting fluids out of the well—vs. other forms of lift that operate at 30% to 50% energy efficiency. But its other operational benefits, like low installation costs, ease of retrieval and repair, high reliability, low downtime, and tolerance to sand and gas production, combine to make jet pumps a dependable and economical solution for offshore wells. These benefits also enable hydraulic jet pumps to work where other artificial lift systems cannot.

Developing the solution
Weatherford worked with the operator to arrive at the optimal jet pump size for the well, which was producing 36°API oil and operating at a water cut of 88%. The prejob planning process involved building inflow performance relationships (IPRs), plots of liquid production rate inflow against flowing bottomhole pressure, to get a sense of the well’s deliverability.

In this case the operator was able to supply the data to build out an accurate IPR for the well. However, this is not always the case. Incomplete, inaccurate or old datasets are common, which results in problems such as oversizing and prematurely having to replace a downhole motor or even the entire pump. Incomplete or inaccurate IPRs do not significantly slow down the
deployment of jet pumps.

When an IPR is not available, Weatherford engineers elaborate a technical analysis based on statistics or data from nearby wells. Later, hydraulic lift technicians install the jet pump, run it for a few days and closely monitor injection pressures and production rates at the surface. If these data indicate that the jet pump is improperly sized, the pump is retrieved from the well and resized to match the precise well conditions.

Even with a properly sized jet pump, the operator was still concerned that this option would exceed its operating budget. Weatherford reviewed the architecture for the subsurface assembly and suggested a design change that would allow the operator to use the jet pump without going over budget. The solution centered on finding a replacement for the well’s subsurface safety valve (SSSV), which is the safety device installed below the jet pump bottomhole assembly to provide emergency shutdown of the well in case of overpressure and to avoid the uncontrolled release of reservoir fluids.

The new design would use the hydraulic jet pump in combination with an automatic downhole master valve (DHMV) to achieve wellbore isolation. The DHMV is less expensive than an SSSV and is designed to hold pressure in both directions. The valve closes when hydrostatic pressure exceeds a preset value and opens when hydrostatic pressure is reduced.

The operator received approval to make this valve change from federal regulators in the Bureau of Safety and Environmental Enforcement. The approved DHMV and jet pump were installed as part of a straddle packer assembly. The lower packer assembly containing the DHMV was deployed downhole and set first. The upper assembly with the jet pump assembly was then run downhole, with the upper packer stabbed into the lower assembly and set. The pump was installed at a seating depth of 2,545 m (8,350 ft) true vertical depth.

This installation option saved the time and cost associated with having to pull the tubing to install a valve and lifting method. Most SSSVs installed as part of the completion design are classified as tubing retrievable; should the valve malfunction, a workover is required to retrieve it. With DHMVs the tubing remains in the hole during installation, and the valve is retrieved via wireline instead of a workover.

Produced water was used as the power fluid, pumped at a rate of about 2,700 bbl/d and an injection pressure of 3,500 psig. The jet pump operated without incident from day one and required about 190 hp to operate. The producing pressure at pump intake was 700 psig, which provided a jet pump production rate of about 700 bbl/d of fluid.

The jet pump has been operating continuously and without incident for more than five years, resulting in a cumulative production of more than 1 MMbbl.