DRILLING TECHNOLOGY

Putting the well in the best place in the least time

 Real-time visualization of high-resolution images drives optimum well placement offshore Nigeria. 

Anselm Okeahialam, Chevron Nigeria Ltd., Lagos, Nigeria; and Stuart Galvin, Schlumberger, Lagos, Nigeria

Even when drilling a mature reservoir already pierced by 52 wells (25 of them horizontal) there can be surprises. Armed with an impressive knowledge base and a comprehensive development plan, Chevron Nigeria-operator of the Nigeria National Petroleum Corp./Chevron Nigeria Ltd. Joint Venture-turned to a new technology to help develop Meji field.

Meji field, discovered in 1964, consists of stacked reservoirs arrayed along a southeast trending rollover anticline and separated by numerous faults. Deposition is of Late Miocene age. The target for the four-well drilling program was an estimated 16 million bbl of oil reserves, representing a production gain of about 9,000 bopd from the field. The reservoir consists of clean middle- to upper-shoreface delta front deposits, has a strong water drive and no gas cap. So the closer the well could be drilled to the ceiling the more reserves could be accessed. Accordingly, key objectives included staying as close to the reservoir ceiling as possible to maximize attic oil access without exiting the reservoir, while staying well above the Oil-Water Contact (OWC). Until now, available technology had been fairly successful in placing 1,000-ft to 2,000-ft laterals within 10 ft of the reservoir’s upper boundary.

Chevron used the Schlumberger PeriScope 15 bed boundary mapper for continuous boundary mapping while drilling. With early warning of approaching formation boundaries and fluid contacts, it would be possible to geosteer four wells into optimum positions on a structure that had little or no structural control.

After identifying most of the anticipated risks, which included structural, stratigraphic and fluid contacts, the company sought a technology that was effective and economical. The tool’s gamma ray is the closest LWD measurement to the bit and is a good indicator of lithology changes. It was used in conjunction with deep-reading directional electromagnetic readings that provided advance warning of approaching boundary conditions. In addition, the tool’s ability to present regional dip is useful for detecting total depth based on real-time dip changes, mapped during drilling. Thus, if a tilting boundary is detected, the drilling engineer can decide to steer down and away from it, because the dip information provides spatial orientation. The ability to make an early TD decision was considered critical, because exiting the formation could reduce the value of the well.

DIRECTIONAL ELECTROMAGNETIC REAL-TIME STEERING

The PeriScope 15 LWD tool system uses an array of axial and radial electromagnetic propagation resistivity antennae to image the formation around the borehole to a radial distance of about 15-ft. Key to the tool’s ability to detect the distance and direction to formation boundaries and fluid contacts are two tilted antennae, R3 and R4, Fig. 1. When the tool approaches a boundary, indicated by a resistivity change, both signal attenuation and phase shift are affected. The signal polarity indicates whether the tool is crossing the boundary from below or from above it.

Fig. 1. Log data inversion shows Well 1’s path, the reservoir top and original well plan. The enhanced area indicates the volume imaged (white earrow) by the tool (above plot). Tilted antennae R3 and R4 detect distance and direction to boundaries and contacts. Polar plots indicate boundary dip and direction above and below the tool.

Range and relative bearing to upper and lower boundaries as well as the boundaries’ dip angles are displayed on polar plots centered on the tool’s axis. The tool system maintains a well’s trajectory within the target reservoir, which generally means avoiding reservoir boundaries or fluid contacts.

WELL PLACEMENT

Four wells were drilled on the prospect-this article describes the first two. Lessons learned from each well directly benefited planning and execution of subsequent wells. For example, azimuthal apparent dip responses from the first well confirmed the general structure. Previously, structural control was very poor, which added to the drilling risk. Dip data updated the model and confirmed structural maps while drilling.

Well 1 was landed in the target reservoir at 4,120 ft TVD. The plan was to drill an 8 ½-in. lateral about 1,000 ft long, close to the reservoir top and parallel to a major normal fault. Schlumberger’s PowerDrive Xceed rotary steerable system drilled and steered the well. Besides the PeriScope 15 tool, the ADN Azimuthal Lithodensity/Neutron tool was in the bottomhole assembly. Real-time data were transmitted directly from the drilling rig to Chevron’s offices, where a team of geosteering engineers were on 24/7 duty providing interpretation. Directional drilling decisions were transmitted to the rig’s driller using a secure chat board and telephone.

Initially, the well was landed within four feet of the reservoir top. However, the logs confirmed the presence of resistivity anisotropy near the upper boundary, so the trajectory was allowed to track slowly away from the boundary into better quality rock. When the reservoir top was detected nine feet away, the bit was steered upward to parallel the reservoir top. At about 6,880-ft MD the tool indicated it was approaching a sub-seismic normal fault with an eight-foot downward throw. The well was successfully steered through the fault block, staying in the highest quality portion of the reservoir, Fig. 1.

The ability to image dip played an important role in making the right decisions, keeping the lateral section close to the reservoir’s upper boundary. As a result, the operator determined that an additional 1.3 million bbl of producible reserves was accessible. The field’s water level was not imaged in this well, indicating that the entire track was well above the OWC.

The second well was drilled immediately after the first, using the same bottomhole assembly. Knowledge gained from Well 1 was immediately put to use. The company was more aggressive in its efforts to stay close to the reservoir top. Well 2 challenges included a low-quality sand layer at the reservoir top and a strong water drive. Placing the wellbore in high-quality rock, but as far away from the OWC as possible, were key priorities. Again, the pre-drill modeling was inaccurate, since the reservoir top came in eight-feet deep. However, the tool identified the reservoir top and landed the well.

The shaly lithology was recognized immediately, but the tool indicated a better quality 100 Ω-m sand just two feet deeper, so the well was steered down into the higher resistivity pay, then turned to track along the top of the zone, Fig. 2. Well 2 was kept within two feet of the pay zone’s top over the lateral’s length, resulting in an additional 700,000 bbl of producible reserves. The well came no closer than 13 ft to the OWC and was considered a success.

Fig. 2. Inversion results show the trajectory of Well 2, relative to the erroneous original plan. After landing in poor quality reservoir, a pay zone was detected down and to the right of the well track (blue lines on the first three polar plots) and the well was steered into it.

REAL-TIME VISION

With clear images and intuitive presentations, it is easy to make on-the-spot directional drilling decisions with confidence. The new directional electromagnetic technology shows a more accurate picture of the geological structure, strata and fluid contacts.

Boundaries with resistivity contrasts as low as 5 Ω-m could be detected as far as 15 ft away. In addition, sub-seismic faults could be detected without a density contrast across the fault. Being able to see dip and determine azimuth and distance to boundaries helps confirm structural maps and calculate reserves volumes. Most importantly, the experience in Well 2 confirmed the tool’s ability to discriminate high quality reservoir rock for optimal well placement.