CECIL COLWELL, Forest Oil Corp.; JIM CRENSHAW and BILL BLAND, Weatherford International Ltd.
Deployment of the MPD system enhanced on-site safety and reduced potential environmental risk by establishing a more efficient operation, including fewer drilling days, smaller influx volumes and safer handling of surface gas.
While the Haynesville shale play offers great potential, it also poses significant challenges. The play is characterized by a network of fractures and faults, as well as very low permeability and high porosity that often result in over-pressurized zones. With depths ranging from 10,000 ft to 14,000 ft, the play also features significant high-pressure, high-temperature (HPHT) conditions that pose obstacles to drilling. The high cost of drilling and completing wells in the Haynesville shale presents a particularly difficult challenge to total well economics. Marginal gas prices, drilling hazards, related non-productive time (NPT), and varying initial production rates and decline rates further challenge the economics faced by operators working in the region.
Economics, drilling efficiency issues and safety concerns posed a multifaceted challenge for Denver-based Forest Oil Corp. in Red River Parish, Louisiana, soon after the company began drilling its first Haynesville wells there in 2009. Pockets of high pressure, frequent influxes of gas, multistage hydraulic fracturing and temperatures that exceeded 300°F were driving up the cost of the wells. With expenses of $40,000 per day for personnel and equipment, the operation was economically compromised by slow rates of penetration (ROPs) in the horizontal sections of the wells, high drilling-related NPT, long drilling times, and safety and environmental concerns related to high levels of nuisance and background gas while drilling.
In addition, the high bottomhole temperatures (BHTs) were causing motors and other downhole tools to rapidly fail. Downhole tool assemblies, such as drilling motors, bits and measurement-while-drilling tools, are only effective for so long at high temperatures before reaching failure mode, particularly when BHTs exceed 320°F.
The downhole tools were spending large parts of their downhole lifetime in drilling flat time, such as circulating or dealing with drilling hazards, which translated to limited motor and tool efficiency for on-bottom drilling time. Operators were making multiple trips in and out of the wells to frequently change out motors, tools and equipment on the drillstring because of slow ROP, high BHT and drilling flat time.
High amounts of drilled gas were a constant challenge for drilling crews, causing overall safety concerns. The rig personnel had varying levels of experience in dealing with nuisance gas, high-pressure/low-volume influxes, and safely managing these events at surface.
Forest Oil investigated changes to drilling techniques that would enable it to accomplish the economic, drilling efficiency and safety goals established by corporate objectives. The company attempted several methods to overcome the drilling efficiency challenges, including increasing the oil-based mud weight density from 14.8 pounds per gallon (ppg) to 16.5 ppg. While the technique is commonly used to counteract frequent gas influxes, it also slows ROP. That approach delivered marginal success in two of the initial six wells, but not enough to significantly reduce well costs and satisfy the operator’s safety and environmental concerns. The increased mud weight kept penetration rates slow, and the company was increasingly concerned that the crew did not have the expertise to handle the drilling conditions and high levels of nuisance gas, which could cause a kick, creating an unregulated release of gas and/or drilling mud. This scenario posed potentially serious safety hazards for personnel and the risk of environmental pollution if the oil-based mud were to be released from the well.
MPD TACKLES MULTIPLE ISSUES
With neither economic nor safety issues resolved, it was clear that conventional methods were not going to meet drilling optimization objectives in the Haynesville environment, so Forest Oil decided to employ managed pressure drilling (MPD). The drilling process control, ability to distinguish background gas from wellbore influxes, and other automation capabilities of a fully automated MPD system were attractive and warranted further investigation.
In April 2010, Forest Oil chose to deploy Weatherford International’s Microflux control system. Introduced in 2006, this MPD system has been applied in more than 105 operations globally, both onshore and offshore.
The MPD system combines high-resolution pressure and flow data in real time during the drilling process to detect and control many common drilling hazards such as ballooning, losses, influxes, early kick and pack-off. Using closed-loop drilling principles, such as rotating control devices, the MPD system precisely controls bottomhole pressures and equivalent circulating density (ECD), accounting for temperature effects, pipe movement, rotation, and changes in fluid properties, Fig. 1.
 |
| Fig. 1. Weatherford’s managed pressure drilling system. |
|
The system provides a combination of high-resolution, mass flow detection and annular pressure data. The driller is continuously informed of wellbore flow characteristics at the bit with regard to potential losses, influx or active total returns. Any variance from total returns is detected in gallons, and the pressures or flowrates are adjusted to re-establish mass balance in the wellbore.
In addition, the ability to conduct dynamic formation integrity tests and pore pressure tests while drilling allows the system to verify the environmental limits of the downhole pressure window (pore pressures and frac gradients), ensuring the proper MPD technique, mud weights and ECD are applied at the appropriate time as determined by existing wellbore conditions. The flexibility of the system permits multiple MPD modes to be used as conditions in the well change or when drilling events occur. For example, the system’s monitoring mode can be used when drilling with a statically overbalanced mud weight; surface backpressure (SBP) mode on connections or while drilling; annular pressure control (APC) mode for maintaining constant bottomhole pressure while drilling or holding backpressure while tripping pipe; and SBP or APC mode for MPD drilling with a statically underbalanced mud weight when drilling within a narrow pressure margin.
MPD IN THE HAYNESVILLE
As MPD is a new method for many operators, hands-on rig crew training is essential to success. In the Haynesville application, the operator required a dynamic and flexible drilling procedure to be adapted on location as well conditions changed. MPD operates as a dynamic response to well conditions, which enhances data available for decisions and enables immediate appropriate response. The increased flexibility of this operating process required rig personnel to transition away from conventional drilling mindsets and become competent in MPD drilling techniques.
With the high resolution of data obtained in the system, there was a learning curve to understand and act on the data provided. The companies implemented a concentrated, onsite training program designed to ensure that rig crews and engineers had a thorough understanding of the MPD system and could identify and properly respond to any flow or well control events. This training was supported by a real-time remote portal viewer of the MPD system that enabled operator and service company engineers to participate in critical wellsite decisions from offsite locations.
The MPD system was installed on the first well in April 2010 with the initial objective to safely handle drilled gas or influxes and dynamically manage the mud weight for improved ROP. Determining the safest method to deplete the gas without weighting up the mud, and thus maintain high ROP in the wells without compromising safety, was critical to operations. The operator also faced uncertainties about the volume of gas present and the potential to encounter any high-pressure pockets.
The MPD system enabled the operator to differentiate between nuisance, or background, gas and any influx or kick. In the first well (Fig. 2), the system was used to successfully drill a 6⅛-in. hole section and reduce the oil-based mud weight through the curve and lateral to TD, which resulted in improved ROP and less drilling flat time.
 |
| Fig. 2. Forest Oil’s Haynesville Red River Parish well design. |
|
By August, four wells had been successfully drilled using the MPD system, which helped the operator achieve the technical, economic and safety objectives. In the drilling events encountered in the four wells, the operator was able to use the system to quickly determine the proper combination of surface backpressure and flow circulating rate to obtain and maintain the desired bottomhole flow stability. Any experienced surface gas, influx or loss events were quickly identified, verified and controlled, allowing mass balance to be restored so the operator could drill ahead with minimal flat time, Fig. 3.
 |
| Fig. 3. Screen display of fully automated MPD process control system. |
|
Managing background gas. The MPD process enables operators to “listen” to the well to determine downhole flow conditions and determine if unexpected flow events are occurring. In these cases, by monitoring flow in vs. flow out, fluid density in vs. fluid density out, and stand pipe pressure, adjustments to the annular pressure profile were made by precise application of SBP.
The system uses high-end quartz pressure sensors for accurate surface backpressure readings and standpipe pressure readings, along with an Emerson coriolis meter to determine mass flowrates, fluid densities and temperature. In the case shown in Fig. 4, nuisance gas entrained in the oil-based mud is breaking out of solution as the returns mud hits the MPD choke system, with the presence of gas being confirmed by a drop in density readings. The corresponding drop in standpipe pressure and, by relation, bottomhole pressure is addressed by a slight choke closure and the building of SBP to replace lost bottomhole pressure. With this technique, two objectives were met: quickly and safely depleting the micro-fracture produced gas, and maintaining low mud weights. Conventional drilling may have dictated the need to weight up and knock back the ever-present nuisance gas, which would force a reduction in ROP.
 |
| Fig. 4. Screen display of background gas encountered in a Haynesville shale well, which was controlled through the use of surface backpressure. |
|
Managing influxes. Unlike many conventional drilling systems, which rely primarily on pressure variations to determine an influx of gas, the MPD system monitors well flow changes and bottomhole pressure, allowing for rapid identification and dynamic management of influxes. The system is able to quickly achieve the proper combination of pressure and flow to provide stability downhole. The system immediately recognizes influxes and integrates the flow data into the software for application of the correct amount of backpressure by the choke’s intelligent system.
This feature proved to be valuable in the Haynesville play, particularly on the second well when a strong high-pressure influx was detected. Using the system, the operator was able to minimize the total influx volume, safely circulate out the influx, and return to full drilling in less than 12 hours, Fig. 5. Mud weight was left unchanged after the high-pressure, micro-fracture gas pocket was successfully depleted, which was verified using the MPD intelligent system for flow checks on subsequent connections.
 |
| Fig. 5. Screen display of MPD system safely addressing background gas and a downhole influx using automated process control. |
|
OPERATIONAL RESULTS
The MPD system had an immediate impact on Forest Oil’s operation in the Haynesville. In comparing the six conventionally drilled wells in the field to the four MPD wells, there was a significant reduction in cost and NPT, as well as a marked decline in the number of days it took to drill the wells, Fig. 6. Effectively managing the influx and loss events early in the process and avoiding an increase in mud weight sped up the entire drilling process and positively impacted the penetration rate. The wells were drilled faster, there were fewer downhole tool failures and longer and better tool motor and bit runs.
 |
| Fig. 6. Based on performance on the first two MPD wells, planned drilling time was decreased to 45 days, vs. 55 days for the conventional wells. The third MPD well (actual) reached TD six days ahead of the shortened schedule. |
|
Specifically, Forest Oil saw a reduction of more than $2.4 million in project cost over the last four wells. The improved ROP resulted in a 48% improvement in lower hole sections in the days-vs.-depth ratio, with total depth reached 15 days ahead of schedule. The reduction in drilling days, along with lower oil-based mud densities, resulted in savings on mud averaging $100,000 per well, or nearly 25%, compared with the six conventionally drilled wells, Table 1. Trips in and out of the well were also decreased significantly.
| Table 1. Six conventionally drilled wells vs. four MPD drilled wells |
 |
In addition, the MPD system was effective in mitigating some of the high-temperature effects in the wells. With the increased efficiency in handling gas influxes, downhole tools could be better utilized for drilling functions, as opposed to other tasks like weighting up or circulating. The operator was able to gain longer, more efficient use out of the downhole tools, in some cases doubling the life of the motors and bits. For example, the average number of bit/motor runs increased from 40–50 hours to more than 150 hours. The total number of downhole tool packages utilized was reduced by half.
Deployment of the MPD system enhanced on-site safety and reduced potential environmental risk by establishing a more efficient operation, including fewer drilling days, smaller influx volumes and safer handling of surface gas. Through rapid detection and corrective action response, the system maintained a much smaller influx volume and handled these events more quickly and safely.
The successful application and initial use of the MPD system in an HPHT shale play has led to further application of this system in unconventional formations and other challenging drilling environments. Forest Oil is planning to deploy the system in future wells in Red River Parish. The company is also using an MPD system for oil sand operations in Narraway, Alberta, to monitor pressure and eliminate an intermediate casing string. 
ACKNOWLEDGMENT
This article was prepared in part from AADE-11-NTCE-55 presented at the 2011 AADE National Technical Conference and Exhibition held in Houston, April 12–14, 2011.
THE AUTHORS
|
 |
CECIL COLWELL is the Senior Vice President of Worldwide Drilling for Forest Oil. He previously served as Vice President of Drilling and Drilling Manager for the Gulf Coast. Prior to joining Forest, he held various positions at Texaco, Amoco, Placid Oil and Colwell Engineering.
|
JIM CRENSHAW serves as the North America Product Line Manager for managed pressure drilling at Weatherford International. With over 30 years of industry experience, he has worked for operators, engineering consultancies and major oilfield service companies in both operational and senior management capacities. Mr. Crenshaw holds a petroleum engineering degree from Texas A&M University. |
BILL BLAND is Weatherford International’s Business Development Manager for the US. |
|
