Production logging in high-angle wells: Middle East examples

World Oil, July, 1998 by Chris Lenn

A production logging tool is designed to overcome physical realities of fluid flow in high-angle wells and gain reliable production data, including fluid type and amount, from all flowing zones

The nature of multiphase, stratified flow in near-horizontal wells has challenged those seeking accurate production logging data from high-angle or horizontal wellbores. Trapped, stagnant fluids and uncertain borehole conditions not only directly affect production but also distort downhole measurements.

Traditional production logging techniques and tools, designed to acquire measurements from vertical wells that are conventionally cemented and perforated, are not suited to high-angle wells that produce stratified flows, often from behind uncemented liners or prepacked screens, Fig. 1. In particular, small changes in wellbore deviation can cause large changes in fluid hold-up and velocity, independent of fluid entry; therefore, independent measurement of hold-up and velocity of all flowing phases is necessary.

A production logging tool has been designed to overcome the physical realities of fluid flow in high-angle wells and gain reliable production data, including fluid type and amount from all flowing zones. The tool was conceived in 1994 through a collaborative association, The Flagship Project, between BP and Schlumberger. The integrated production logging tool string consists of a pressure/temperature sonde, gamma ray detector, pulsed neutron activation tool (RST Reservoir Saturation Tool), two aligned fluid imaging tools (FloView Plus), a fluid marker injector (PVL Phase Velocity Log), and one or more spinners, Fig. 2.

Initial application of the PL Flagship tool string was in BP's extended-reach Wytch Farm wells, which straddle England's southern coastline. Wells in this field have repeatedly achieved extended-reach records. The PL Flagship string measured two-phase flow in cemented and perforated liners in these wells and has since been used successfully elsewhere.

This article illustrates the tool string's application in two large openhole carbonate completions in the Middle East, with a look at downhole flow regime detail (possible with fluid imaging capability of the PL Flagship). For an in-depth look at the results of the PL Flagship string's application in the Wytch Farm wells, see Schlumberger's Oilfield Review, Vol. 8, No. 4.

EVALUATING HIGH-ANGLE MIDDLE EAST WELLS

In the Middle East, the PL Flagship string faced quite different conditions than those found in the North Sea and UK, where it was initially tested. In particular, large openhole completions in carbonate reservoirs are frequently encountered.

Oil well. After being acidized, a new openhole well produced oil at the surface with no water. It was believed, however, that downhole oil flow was being affected by stagnant water sumps along the lower wellbore areas.

When conventionally logged, the well was producing below bubble point, causing gas to accumulate in local high points in the wellbore and making conventional sensor data uninterpretable. To obtain a reliable flow profile under these conditions, the PL Flagship string was run on 2-in. coiled tubing (CT) with the well both flowing and shut-in. While the horizontal section was nearly 7,000 ft, the bottom 3,000 ft could not be logged due to CT lock-up.

Three fluid phases (oil, gas and water) were successfully identified down hole, despite dry oil surface production, Fig. 3. As suspected, flow behavior was being dominated by water sumps (blue on low side of wellbore) and gas traps (yellow on high side of wellbore).

Logs also showed that the well was producing along a significant part of its length, although not evenly. Little production was coming from the top 1,000 ft, and about 750 bpd, or 20% of production, was coming from the lowest, unlogged well section.

PVL data was crucial for confirming oil production. Its measurements were combined with those of the FloView Plus tool to calculate the amount of production coming from the lowest, unlogged areas.

PL Flagship sensors were able to quantify production volume coming from the unlogged well portion, whereas with conventional methods, the spinner would be running through a stagnant water trap, leading to an erroneous flow profile.

Logs from upper and lower well portions are displayed with fluid holdup images added to illustrate the support possible between the various measurements, Fig. 4. These images show the distribution of hydrocarbons vs. water at various points along the horizontal wellbore. They were derived from the FloView Plus sensors.

A review of Fig. 4 shows that spinner response was dominated by water sumps and gas traps along much of the wellbore. In particular, spinner behavior over the first 1,000 ft was totally erratic. In the last 400 ft, the spinners saw only a stagnant water sump, although oil was flowing on top, as indicated by the accompanying hold-up image. Water sumps were seen on the hold-up or FloView images during both shut-in and flowing passes, and gas traps were easily identified with RST data, as sigma quality in the openhole completion was excellent.