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Technology Update

Resistivity, Imaging-While-Drilling Tool Helps Well Placement in Chinese Tight Reservoirs

Two case studies describe the use of a new resistivity and imaging-while-drilling tool that was used to improve well placement in the Sichuan Basin of central ­China—a drilling environment presenting high levels of geological uncertainty. The first case involved the technology’s application in a very thin tight dolomite gas reservoir, and the second case involved the first commercial development well in the region to target a carbonate oil reservoir. In addition to assisting well placement, the technology enabled valuable information about the natural fracture network to be obtained to support the completions design.


The Sichuan Basin holds the biggest gas reserves in China and is the country’s leading gas production region. The basin rests in a major compressional tectonic area, highly compressed and characterized by thrust-faulted anticlines. Modern exploration and production started in the 1950s. Most of the gas and modest quantities of oil are produced from fractured carbonate and low-permeability sandstone reservoirs.

PetroChina Southwest Oil & Gas Company (SWOGC)—one of the biggest subsidiaries of PetroChina—operates in the basin. It has more than 100 exploration and development concessions in the region, covering a total of 180 000 km2. Natural gas reserves in place are 842.2 billion m3, with estimated recoverable reserves of 320 billion m3.

During the early phases of exploration and development, wells were drilled vertically. Horizontal wells were introduced during the 1990s to enhance production from tight reservoir plays, which include limestone, dolomite, and tight sands. Logging-while-drilling (LWD) applications used for formation evaluation and well placement typically included propagation resistivity, density/porosity measurements, and real-time density image logging.

Today, after more than 20 years of production, most of the thickest tight gas reservoirs have been intensively developed. Since 2011, PetroChina SWOGC has increasingly targeted ever thinner tight gas formations using long horizontal drilling combined with multistage hydraulic fracturing. However, several subsurface challenges needed to be overcome for these efforts to succeed, particularly because of the extensive faults and fractures in the reservoir rock.

To meet these challenges, and enhance reservoir understanding, the company has deployed advanced LWD real-time acquisition and transmission technology providing high-resolution electrical borehole images, azimuthal gamma ray, and multidepth formation resistivity measurements.

The New Tool

The new LWD capability deployed in these case studies provides high-resolution resistivity and borehole images around the full circumference of the borehole in conductive mud environments. The MicroScope high-resolution resistivity and imaging-while-drilling technology uses a 4¾-in. tool in 5⅞-in. to 6½-in. hole sizes that measures azimuthally focused laterolog resistivity at multiple depths of investigation. Also measured are azimuthal gamma ray and mud resistivity. Formation resistivity measurements, high-resolution borehole images, and azimuthal gamma ray data are transmitted uphole in real time, facilitating proactive well placement decisions.

This technology is suitable for use in diverse and challenging environments, including unconventional shale plays, and carbonate and clastic reservoirs. It enables enhanced formation evaluation, optimal placement of horizontal wells, and identification of fractures and faults for optimization of completion design.

A multidisciplinary team of oilfield operator and service company experts provided support for the resistivity measurement and imaging-while-drilling technology and the well placement and completion operations. Based in an interactive drilling operations support center of PetroChina SWOGC in Sichuan, a well placement team interpreted the real-time LWD data and guided the geosteering operations. After drilling, specialists from the service company interpreted the natural fracture network, modeled the reservoir structure, and recommended how the well could be optimally segmented during completions.

Case Study: Thin Dolomite Gas Reservoir

Making use of the new LWD capability, PetroChina SWOGC drilled a long horizontal well in a dolomite gas reservoir, where the target zone was predicted to be between 1 m and 2 m thick. The major challenges were to stay in the producing zone and identify fractures to help ­optimize completions. As it was a major compressional tectonic area, reverse/thrust faults and high structural dip uncertainty were expected. In addition, the reservoir was likely to exhibit significant lateral changes in thickness and petrophysical properties. The nearest offset well was more than 3 km away—too far to be useful as a means of reducing drilling uncertainty in an area characterized by rapid lateral structural and stratigraphic change.

The LWD technology provided a high-resolution resistivity image that clearly identified and defined the formation dips, faults, and fractures along the horizontal section. Even with the local structural undulations, variations in target zone thickness, and lateral property changes along the horizontal section, these images helped the operator to optimize geosteering as the well was drilled (Fig. 1). The 1095-m horizontal section was drilled with 91% in zone—exceeding the minimum requirement of 80%—and with good trip gas readings throughout the section.

The well was completed in one run in a total of 151 drilling hours. The initial gas production of 120 000 m3/d ex­ceeded the operator’s production goal by 33%, compared with similar previous wells. The technology also provided valuable information about natural fractures (Fig. 1) that aided the design of hydraulic fracturing stages for completion optimization. In particular, it enabled the well to be segmented into zones of high- and low-density natural fracturing. The success of this well has enhanced the potential of thin tight gas/reservoir development in the basin. Several wells have now been planned in different target zones.

Case Study: Tight Carbonate Oil Reservoir

Modest oil reserves have been discovered concurrently with gas development in an area of the basin. PetroChina SWOGC used the resistivity and imaging-while-drilling tool to drill the first commercial oil well in the carbonate reservoir. A long horizontal well was planned in a reservoir bounded by two complex major faults. The formation was predicted to be 5 m to 7 m thick; however, the well was expected to encounter minor faults. To be successful, the company needed to identify the formation dips, faults, and fractures along the section being drilled. There were no nearby control wells to study to reduce the uncertainty.

During drilling, the high-resolution borehole images—combined with other key measurements from the tool—facilitated proactive geosteering decisions (Fig. 2). In one instance, the technology identified a fault on the west side of the well and made an azimuthal adjustment to shift the trajectory eastward to avoid exiting the formation at the fault. A total of 810 m was drilled in the horizontal section, 100% in zone with good oil shows throughout. The well was completed in a single run with a total of 265 circulating hours and 155 drilling hours. Identification and analysis of fractures along the horizontal section provided valuable information to optimize completion and hydraulic fracture staging design.


PetroChina SWOGC has used the resistivity and imaging-while-drilling tool to further oil and gas development in the Sichuan Basin and is applying it in more thin tight gas and carbonate oil reservoirs. The technology has also been applied recently in a thick tight sandstone gas reservoir to enhance production by steering a horizontal wellbore into the most highly fractured areas of the reservoir.

Wireless Wellbore—The Way Ahead

The trend of increasing wellbore complexity for extended reservoir contact and greater reservoir ­heterogeneity demands improved monitoring and control solutions. Traditionally, the only option has been the deployment of a cabled system, but this limits the application of intelligent well technology to new installations or workovers. In any case, cabled systems are not always possible in new installations, especially where the completion is discontinuous, and slimhole or monobore completions may not allow cables to be deployed along the tubing string.

Wireless technology is proving to be a more flexible alternative to addressing the issues of permanent downhole monitoring. Tendeka’s wireless gauge, an interventionless completion technology that has been successfully deployed in the North Sea, allows real-time flowing bottomhole pressure (FBHP) to be efficiently transmitted to the surface, an attractive option for wells, in which the cabled gauge system has failed or was not initially installed. Originally designed to 3.5 in., the company has recently produced a 2.25 in. version.

Benefits of Wireless Technology

The system transmits data from the lower completion to the surface via pressure pulses. The tool design allows the well’s production to be partially choked for a short time to create a pressure pulse, which is detectable on the surface pressure gauge. The well’s energy is used to transmit data to surface, thereby reducing power consumption, and the system requires no additional surface installation or pickup because an existing tubing head pressure gauge can be used to detect the pulse train. For most operators, the system can be deployed by a single intervention, allowing highly accurate data to be sourced almost instantaneously for a fraction of the cost of a recompletion.

Compared with a memory gauge system, it allows data to be collected in real time and provides a continuous confirmation of operation. The gauge can be set in blank pipe, giving optimal freedom for installation depth, and it can be installed as close to the producing interval as required. A benefit of using pressure pulse transmission is the ease of installation. No retrofitting of topside equipment is required, and many of the technical and contractual issues are avoided when introducing a new monitoring system.

Successful Deployment

A major operator in the North Sea retrofitted the 3.5 in. wireless pressure and temperature gauge at 2200 m in a low-pressure (32 bar) gas well offshore Norway. The existing wellhead pressure sensor was used to capture the wireless signal and extract the data, therefore, no extra infrastructure
was required.

The application was especially challenging because the well was a marginal producer and the wellhead pressure had large background pressure variations, because of limited well deliverability. Despite these conditions, pressure pulse transmission proved effective. Even if the well starts to significantly deplete while the wireless downhole gauge is installed, the gauge itself will modify its pressure pulsing method to ensure that a detectable pulse train is transmitted to surface.

The wireless gauge is unable to transmit signals in a nonflowing or shut-in well, because a flow regime is required to produce the pressure pulses. The tool can record pressure buildup data during shut-in periods, and, once well production is restarted, the stored data can be transmitted to surface. During this installation, there were periods of shut-in while surface maintenance was conducted. The tool successfully recognized the shut-in events and entered its power saving hibernation mode. When the well resumed production, the technology reactivated itself and the first telegrams transmitted following the restart gave accurate shut-in pressure data to surface.

This application, and two others undertaken at the time, demonstrated that the system functions not only in oil wells, but also in gas wells and wells with a high gas/oil ratio. It was demonstrated that the wireless gauge could function in wells with slug flow and high levels of pressure/noise variations on surface. During shut-in periods, the tool successfully recorded the shut-in data and transmitted it to surface when production was resumed. The 3.5 in. version of the gauge was recently successfully installed in another gas well in the North Sea.

Wide Application

The downhole pressure temperature gauge can operate in water injection wells, in which a back pressure is created instead on the injection fluid, which generates a pressure pulse train on the surface. A recent development in the wireless technology products now also allows the measurement of injection rate. By measuring the pressure drop across a modified venturi, an accurate flow rate can be calculated. Flow loop testing has verified that the method is extremely accurate when used in single phase fluids, such as with water injection applications. This allows the gauge to be run between injection intervals, reporting on the pressure, temperature and rate split between zones. The information is then transmitted to the surface using wireless telemetry.

The susceptibility of downhole mechanical pressure counting activation mechanisms to debris ingress has resulted in numerous in-well failures of these systems. Using a built-in pressure transducer, the wireless technology is able to detect pressure pulses from the surface. Unlike mechanical systems, which become jammed when covered in debris, electronic systems are still able to register pressure changes applied from surface even through a few meters of barite or other wellbore debris. Furthermore, electronic systems are fully programmable to detect a pressure sequence that cannot be accidentally created in normal operations. In the event of a pressure pulse transmission not reaching the tool, the electronics can be programmed to activate at a preset time interval. The final backup is an acoustic pickup, which receives a signal from a downhole tool hundreds of meters away.

Two systems have been developed based on the surface-to-bottomhole wireless communication. The first allows the opening of a completion plug without intervention. The development was driven by an operating company struggling to recover completion plugs after high-pressure stimulation from above. It is suspected that the high differential pressure across the plug causes sufficient deformation for the completion plug to become permanently attached to the nipple profile. In the replacement wireless system, rather than recovering the completion plug, the wireless plug opens its flow ports in response to the programmed signature, thus allowing production or injection to take place across the device. This saves the single wireline run to recover the plug and allows a potentially large fishing operation for plugs that have become permanently fixed to the nipple profile.

The second wireless activation system provides a remote firing signal for downhole barrier plugs, providing a reliable alternative to the suppliers’ mechanical ratchet-style activation. Downhole barrier plugs are especially susceptible to debris since any fallout while running the upper completion ends up on top of the barrier plug and around its mechanical activation port. The wireless pressure monitoring system does not suffer from these problems. It has a substantially charged pressure chamber, which is released to activate the barrier plug on receipt of the appropriate signaling from surface.

Inflow Control

The latest developments in wireless technology allow these systems to operate inflow control valves. This will bring with it a change in the way that operating companies design, test, stimulate, and operate maximum reservoir contact wells. Locations that could not previously be controlled, such as within the laterals of a multilateral well, or at the farthest extent of a long openhole lateral, can now be controlled using wireless signaling. Combining lower completion technology that  incorporates zonal isolation packers and inflow control devices with wireless intelligent downhole devices allows new and effective methods of reservoir inflow control to be developed. Because each wireless inflow control valve is autonomous, no cabling is required between devices, thus allowing a large cost saving in control lines and downhole connectors. Drillers are also offered more flexibility in rotating the completion while running in hole without risking damage to externally strapped control lines.