At-Bit Inclination, Gamma, and Imaging System Tracks Productive Zone in Complex Geology
Robert Flook, Will Alexander, SPE, Dave List, and Bob Sencenbaugh, SPE, Fidelity Exploration & Production; Breck Enoch, Aaron J. Wheeler, SPE, Allen Starkey, SPE, and Allan Rennie, SPE, Schlumberger
In unconventional resource plays and fields with structural or stratigraphic complexities, reliable geosteering of horizontal laterals is essential to economic success. Each foot drilled out of zone represents a potential loss of production revenue. Using real-time logging-while-drilling (LWD) data can reduce directional drilling risk. However, conventional bed boundary imaging tools are typically located far behind the drill bit. This creates a significant lag in response time and increases the odds of exiting the target interval.
The recent introduction of an at-bit inclination, gamma ray, and imaging technology has enabled Fidelity Exploration & Production to optimize well placement in a target formation of the Paradox Basin in Utah—despite unexpected faults and local changes in formation dip that were not clearly resolved with seismic data.
The Geological Challenge
During the Pennsylvanian period, the Paradox Basin was rapidly subsiding and filling with thick, cyclic sequences of marine carbonates, evaporates, silts, and shales. Relatively thin, reservoir-quality clastic and carbonate formations became interbedded within organic-rich shales, surrounded by thick salt deposits. Salt above and below these self-sourced oil and natural gas reservoirs provides critical sealing capacity, while preserving overpressures generated during hydrocarbon maturation. However, the thicknesses of potential reservoirs vary as a result of syndepositional faulting and subsequent salt movement, dissolution, and collapse. Many exhibit open, near-vertical fractures controlled by regional tectonics and local folding because of salt flows over anticlines and underlying fault blocks.
Local thickness variations, folding, and subseismic faulting of Paradox reservoirs have presented significant challenges to operators. One target interval, a dolomite-silica silt reservoir enclosed in a fractured and overpressured shale formation, averages 40-ft thickness in southwestern Utah.
Drilling activity there has undergone two distinct phases, with varying degrees of success. The first phase, from the 1960s through the early 1980s, included the drilling and completion of almost a dozen vertical wells. One well was an economic success, producing more than 1 million bbl of oil and establishing the formation’s potential. Horizontal drilling, introduced in the early 1990s, increased the probability of encountering natural fractures that influence production. Roughly half of these wells produced commercial oil, including one that has yielded more than 600,000 bbl to date.
When Fidelity began exploratory drilling in the area, targeting this thin carbonate interval, some wells encountered unanticipated normal and reverse faults, as well as sudden formation dip changes often caused by localized folding. Conventional measurement-while-drilling (MWD) gamma-only logging configurations place the measurement tools by 35 ft to 65 ft behind the bit. Given the structural complexities of the play, traditional technology could not provide sufficiently rapid reaction time to stay within the target zone. To meet the horizontal geosteering challenge, Fidelity selected PathFinder Services to deliver the real-time at-bit gamma ray imaging technology, commercialized in March 2012. Previously, the system had been successfully field tested in coalbed methane, heavy oil, and shale plays in North America and Australia.
New Geosteering Technology
The iPZIG at-bit inclination, gamma ray, and imaging system is the industry’s first gamma imaging tool positioned directly behind the bit. Developed specifically for unconventional oil and gas plays and high-efficiency drilling applications, the technology ensures greater directional control and accuracy than conventional technologies. In addition to total natural gamma ray measurements, it provides at-bit gamma ray imaging, dynamic inclination data, revolutions per minute, and temperature. Using the real-time data, drilling engineers and geologists can quickly identify changes in lithology and orientation of the bottomhole assembly (BHA) to maintain well placement within the target zone, or to steer back into it sooner if the zone is lost.
Combining the directional drilling and MWD/LWD capabilities with real-time forward modeling software accurately and cost-effectively optimizes well placement and trajectory while drilling. Correlating petrophysical log data from offset wells with the current directional well plan and structural information, the system produces a predicted earth model. While drilling, at-bit gamma ray imaging data continuously update the model to compute the dip of bedding planes and determine the position of the well path in the formation, allowing time to implement critical directional corrections. Having the “closest-to-the-bit” sensor, the system provides earlier bed boundary detection and facilitates more rapid geosteering adjustments, thereby maximizing productive reservoir contact even in the presence of complex geology.
Case Study: Fractured Dolomite Reservoir
Given the geologic uncertainties of the highly dynamic structure in the Paradox Basin, Fidelity decided to use the new at-bit inclination and gamma ray imaging technology for a series of horizontal appraisal wells drilled in 2012. The ideal section of the target consists of a fractured 12-ft dolomite bounded by two secondary intervals. In part because of a lack of unexpected faulting, the first four wells successfully tracked the productive zone for almost 100 percent of the lateral section. However, the fifth well proved much more challenging. Seismic data, which had helped steer previous wells, provided inconclusive resolution of the formation in this area. Without real-time, at-bit inclination measurements and gamma ray imaging (Fig. 1), it would have been difficult to drill a successful well.
While drilling the pilot hole, the target formation came in approximately 250 ft shallower than expected, which created the initial drilling challenge. Uncertainties in projecting the target formation’s location continued to present challenges to the use of conventional MWD gamma ray correlations in building the curve through large sections of salt. Upon successfully landing the curve to position the wellbore in the target zone, a trip was made to add at-bit imaging technology to the lateral BHA (Fig. 2).
Initial formation dip angles had been projected from 2° updip to 3° downdip. However, after landing in the target interval, dips calculated from at-bit gamma imaging averaged 5° updip, rapidly rising to more than 9° over a span of 560 ft measured depth (MD). At that point, the wellbore crossed a large, unexpected fault, exiting the dolomite and fractured shale formation and entering an undifferentiated Paradox salt. The throw, amplitude, and direction of the fault were unknown. A normal fault with downward throw of more than 60 ft would place the wellbore in the salt above the shale. In the case of a reverse fault, the well would be in the salt below the shale. Suspecting that the throw had been downward, the drilling team decided to drill ahead, dropping angle from 100° to 90° and back to 93°, until logging responses and cuttings analysis could identify either the top or base of the formation.
After confirming that the wellbore was in the salt above the formation, the team decided to back up and initiate an openhole sidetrack with the aid of at-bit inclination data to reposition the wellbore back within the primary target zone. Measuring an inclination change of more than 4° down, the system confirmed that the sidetrack had been achieved. This saved valuable rig time because there was no need for a trip to change the drilling assembly. The sidetrack successfully re-entered the top of the reservoir after 560 ft MD of drilling.
An additional 2,000 ft MD of lateral was drilled before calling total depth. Over this interval, formation dips changed a number of times because of localized folding and additional near-vertical faults. The fault locations were interpreted based on real-time gamma ray image logs. The first fault, with an estimated 7 ft displacement, positioned the wellbore out of the ideal target zone. While drilling down, the wellbore crossed an additional fault with an estimated 14-ft throw and re-entered the dolomite. Subsequently, the lateral crossed the upper boundary of the target interval again, because of another change in formation dip.
In each of these situations, at-bit logging measurements reduced the time required to recognize the formation change. An apparent local dip was calculated in real time from bedding features interpreted in at-bit gamma images, thus enabling a quick response from the drilling team. The well trajectory was revised in each case, and the wellbore repositioned within the primary target zone.
Based on real-time measurements and interpretations from this new at-bit inclination and gamma ray imaging system, 85% of the lateral in Fidelity’s fifth horizontal well remained within the targeted interval. This was an exceptional outcome, given the geological challenges. Because of the success of recent appraisal and development drilling, Fidelity plans to deploy the same technology and pay zone geosteering services in future wells in the Paradox Basin play.
Oil Rim Tool Measures Reservoir Fluids Continuously in Real Time, Below Pump
Defining the reservoir by its porosity, permeability, fluid content, water saturation, and behavior is one of the predrilling goals of exploration and production teams, with the aim of optimizing reservoir production over the life of the field.
Advances in Reservoir Characterization
Very few 2D measurements of any kind are taken from inside a wellbore, except for temperature and reservoir microseismic activity. Distributed temperature sensing (DTS), which uses fiber-optic cables, can provide a full temperature profile. However, to obtain pressure, flow, or fluid information, results are extrapolated and mathematically calculated with an inferred answer. Thus, it does not measure the reservoir directly, continuously, and in real time.
Some oil companies are moving toward time-lapse, 4D, seismic techniques that can identify infill drilling opportunities, predict flood fronts, and help avoid early water breakthroughs, despite the cost and complexity of these techniques. Seismic surveys are mostly for the identification of rock formations and subsurface faults, and much of the fluid analysis is inferred from these rather than directly measured.
Knowledge of the position and thickness of the oil rim in particular is critical for effective reservoir observation. To achieve maximum production, it is important not only to be able to measure the effects of injection operations on a reservoir, but also to monitor long-term reservoir movement and behavior. The only alternative way to keep track of the position of an oil rim is with periodic logging surveys, which can be both inaccurate and expensive.
Advances in seismic survey techniques have enabled much greater analysis of fluid chamber and reservoir movement. The gradual development and deployment of this type of technology has taken more than 50 years from single-point seismic source methods using an electronic transponder to 4D methods, which can map the movements, fluids, and sensitivities in the reservoir.
A Clearer Vision
With dwindling hydrocarbon reserves and increasing oil and gas demand, innovation in characterizing reservoirs is crucial to sustaining supply. Reservoir geophysics incorporating the latest software and reservoir characterization techniques is bringing significant improvements to production in existing fields.
Production geoscientists are heavily involved in characterizing reservoirs, particularly describing how reservoirs have been affected by ongoing production processes. The combined use of time-lapse and multicomponent data, such as seismic, logging analysis, and DTS, has had a dramatic impact on reservoir understanding that has led to improved production over the life of the field.
Knowledge and understanding of how production processes can be modified and enhanced in accordance with ongoing reservoir activity has become close to a reality. Continuous, real-time fluid modeling with high resolution is notoriously difficult because of the range of porosities and geometries. Nonetheless, advances have improved the ability of geoscientists to determine and examine a range of reservoir characteristics, including:
- Contents, fluid movements, and behavior
- Static pressure
- Flow and porosity
- Changes such as water saturation, reservoir depletion, temperature, and pressure that occur as the reservoir is produced
- Subseismic resolution faults and other production barriers
Most production logging and pressure measurement may be straightforward in naturally producing wells, but with approximately 95% of the world’s oil wells unable to produce naturally, the technology and tools required become more complex.
The use of a pump can create problems for instrument systems. The producing zone is usually below the pump, an area in which few analysis tools can be used while the pump is running. The size of the pump may also mean that few production logging tools can be run into the wellbore. Thus, analysis of activity below the pump is virtually a blind exercise. The development of cable-based sensors in conjunction with new ground fault immune technology for monitoring electric submersible pumps (ESPs) allows complicated data to be transmitted from below an ESP.
The demand for a device that can work below the pump and provide a real-time measurement of fluids has long been a holy grail for the reservoir engineer. A technology that will measure the position of the top and bottom of the oil rim in observation wells and potentially allow fluid measurement below pumps is under development.
A View From the Wire
Reservoir characterization models are used to simulate the behavior of the fluids in the reservoir under different conditions to determine the optimal production techniques to maximize production. The Zenith True Oil Rim Measurement (ZTORM) system provides reservoir engineers with dynamic brine/oil and gas/oil measurements for the first time, enabling accurate observation of reservoir levels, depletion, and fluid behavior, and steam flood applications for monitoring purposes. The information helps engineers protect the reservoir against water coning.
The system is a cable-based sensor that measures the fluid contacts anywhere along its length. It can be lowered into live observation wells (Fig. 1) using a crane and wellhead equipment to allow rigless deployment.
The technology delivers high-resolution measurement for oil and water simultaneously in real time and provides a new measurement capability. At present, the system is designed for observation wells in which the fluids are settled, allowing it to measure the depth of the water and oil simultaneously. It can be used as a permanent or semipermanent installation, and the information that it provides includes
- Brine/oil interface level
- Oil/gas interface level
- Reservoir sump pressure
- Reservoir sump temperature
- Gas cap pressure
- Gas cap temperature
- Confidence level on measurement
- Status register
In general, the data measured by the system is relatively simple and is transmitted digitally from downhole to the surface. As always, the most complex information will involve the behavior of the well. In some cases, it may be beneficial to reproduce the signals that the system has read. For this, Zenith has a test rig in which downhole conditions are simulated so that the reproduced readings are validated by observation.
The system can be run in hole with a mobile crane on an existing observation well with perforations and can be installed on a live well. The installation can be done on a turnkey basis without the need for a workover rig. The device is designed for a long service life and can be employed over lengthy periods.
For observation wells with a simple cased hole, the system is supplied with a surface actuated anchor for easy deployment and retrieval.
The system’s cable is able to respond to the fluids that surround it. It does this over its whole length, so it must be fully immersed in the fluids being examined. The cable is made of advanced polymer, steel, and wire and has a tensile core and a hard outer shell for pres-
The electronics that transmit the signals from the system’s two pressure sensors are based on technology that has been used by the oil industry for more than 20 years and by Zenith for 9 years with very high success.
Viability and Reliability
Developed over the past 5 years, the system has been extensively proved in a test rig at the company’s headquarters in Inverurie, Scotland. A simulated oil rim was created thousands of feet beneath the surface. The position of the rim could be moved under computer control, thus allowing the sensor systems to be evaluated for operating range and accuracy resolution.
Results confirmed good long-term stability and accuracy of all fluid interface measurements, as well as very good resolution and sensitivity, measured to the scale of a few centimeters. Features have been added to improve the system’s gas/oil interface sensitivity and the mechanical design allows the option of rigless deployment. The materials used to build the system were developed to enable its use in harsh environments.
Providing permanent pressure gauges at the top and bottom of the sensor array gives the operator wellbore measurements, as well as level information, which can be used to cross check fluid level readings from the sensor cable. The level information can include a pressure gradient survey at installation, if needed.
The system is capable of measuring more than two fluid interfaces, and there is ongoing development to extend the system’s capabilities. A successful feasibility study has been carried out, and the system has measured a slug of oil floating upward in a pipe and settling on water at a 4,000 ft depth measured along a wire. Thus, the system is able to view and image moving fluids. Several near-term field trials are in discussion with operators.
Globally, the size of hydrocarbon discoveries is decreasing while demand for oil and gas continues to grow. In many countries, the rate of production exceeds the rate of reserves replacement. Yet sufficient reserves may be there, if improved technology can enable them to be located or extracted more efficiently.
Reservoir geophysics combined with the latest software and reservoir characterization techniques is bringing significant improvements to production in existing fields. The continuous improvement of production efficiency and extension of field life will likely require a more continuous process of reservoir monitoring and depletion analysis that incorporates much higher levels of detail than before.
The ZTORM system allows direct empirical measurement of reservoir fluids in real time, taking responses directly from the different characteristics of the oil, water, and gas. It is a continuous, real-time 2D tool that has the potential to run below the pump and is not as expensive or complex as 4D seismic. The fluid level system is unique so the measurement techniques will be new to the oil industry. While this poses a challenge, the new level of information obtained on reservoir characteristics and behavior has the potential to bridge the gap between reservoir analysts and production engineers by providing a detailed, real-time visual image of how fluids migrate and flow throughout the reservoir.