Underbalanced Drilling With Coiled Tubing in Marginal Shallow Wells
The complete paper describes a recent directional coiled-tubing drilling (DCTD) job completed for an independent operator in the Appalachian Basin.
The complete paper describes a recent directional coiled-tubing drilling (DCTD) job completed for an independent operator in the Appalachian Basin. The objective was to access target zones identified as adjacent to a recently drilled vertical well using a lateral sidetrack. The project was ultimately successful in that a dry hole was re-entered and sidetracked to create a productive well.
The Economic Equation
The target of the project was to define drilling efficiency in terms of cost per production rate. This measure takes the initial production into account and ties together the ability of the driller to make hole in the direction required with the ability to select a productive part of the formation.
Recognizing that each stage of well construction can affect another, a multidisciplinary approach was adopted that included input from geology, geophysics, reservoir engineering, and drilling and completions engineering. Local experience with offset wells also was an important input, allowing for the fact that this experience was limited to vertical wells drilled with air or in an overbalanced condition.
The area chosen for the case study was in a well-understood area containing numerous offset wells with which to compare production and a known geology against which to plan the well. The wells typically do not exceed 2,500 ft in depth and were exclusively vertical. Four such wells had been drilled in the immediate vicinity in the previous year, three of which are currently on production at the time of writing at rates ranging from 10 to 25 B/D with varying levels of associated water production. Although one of the wells showed promise of production, the well turned out to be dry and the planned 4½-in. production casing string was not run and the well was not completed. The uncased well was chosen for the case study because it had the shortest payback period if it could be made to produce at a rate similar to those of neighboring wells.
A 3D seismic survey of the area had identified a subsurface ridge that could be acting as a trap (Fig. 1). This ridge was selected as the target of the new well. A well path was planned that tracked approximately 15 ft below the top of the reservoir and along the top of the ridge, a depth low enough to access the reservoir but not so low that it might access the oil/water contact believed to be 40 ft below the reservoir top.
A DCTD system was used for this well. The enabling technology for this well was a 31/5-in. directional drilling bottomhole assembly (BHA) with real-time measurement-while-drilling (MWD) and steering capabilities. The directional control was provided by a magnetic surveying tool and a downhole rotating orienter in the BHA. The orienter allowed both curved and straight sections of the wellbore to be drilled in the same run through its ability to rotate continuously.
The modules contained within the DCTD package included the following:
- A cable head allows termination of the wireline into the tool string.
- An electric release allows the coiled tubing and wireline to be safely removed from the BHA in case of a stuck-pipe incident.
- An orienter directs the tool face in the desired direction.
- The MWD sensor package provides real-time downhole measurements.
- A circulation valve allows circulation to bypass the motor when tripping.
The remainder of the directional-drilling BHA consisted of a slimhole tubing-end connector, a 2⅞-in. downhole motor with an adjustable bent housing, and a polycrystalline-diamond-compact drill bit. A 3¾-in. drill bit was used for this well, as dictated by the drift diameter of the 4½-in. casing used.
The MWD-sensor package provided real-time magnetic surveys and internal and external pressure, internal and external temperature, and gamma measurements. The package also contained vibration data that output the average and peak vibration levels measured every second. The high density of data is particularly advantageous for steering the BHA and, coupled with the short distance from the bit to the survey tool, allowed for accurate wellbore placement.
The BHA was run on approximately 10,000 ft of 2⅜-in. coiled tubing with a seven-conductor electric line inserted. The total length of the BHA was short enough to allow it to be contained within the length of a 48-ft lubricator. This permitted the BHA to be deployed safely and efficiently in one run from the lubricator above the blowout preventers. Produced water was used as the drilling fluid for the overbalanced section, and the fluid column was then lightened by the addition of cryogenic nitrogen for the underbalanced section.
The Planning Process
The original vertical well chosen for the re-entry was drilled with a rotary rig. The last casing string was set to a depth of 653 ft. A 6¼-in. hole then was conventionally drilled vertically to a depth of 2,600 ft and was abandoned temporarily before the final casing string was run because the well was found to be dry.
3D Seismic. When processing 3D seismic data, maintaining the integrity of the data is imperative, keeping in mind that even intermittent reflective events and noise may represent variable rock characteristics and reservoir anisotropies. A local understanding of the geology is always an advantage for the processing geophysicist.
Drilling Engineering Models. Modeling software developed specifically for DCTD was used to simulate hole cleaning, tubing forces, circulating pressures, and other relevant drilling factors and parameters. The targets and drilling fluid were agreed upon with the operator. A trajectory was created that met the geological targets before being run through the software again to assess drilling parameters. Iterations of this process were carried out until the most-suitable well path was determined.
Two options were considered:
- Drilling a 6⅛-in.-diameter hole with a 5-in. DCTD BHA from the existing 7-in. casing without running an extra casing
- Running a 4½-in. casing and drilling a 3¾-in.-diameter hole with a 31/5-in. DCTD BHA
The latter option was chosen even though both options were technically feasible. The 7-in. casing was not deep enough to straddle the potentially troublesome shale zones that would have to be drilled through, so avoiding the extra cost of the 4½-in. casing was not possible.
Final Well Plan. First, a kickoff cement plug was set from the total depth of the original wellbore to above the kickoff depth. This plug was used for the kickoff but also served to isolate the previous wellbore from the new well. Next, a casing string was run and cemented above the kickoff plug. A mouse hole was drilled and cased next to the wellhead to allow easy rig up. The BHA could be changed out quickly because it was made up and prepared horizontally before being picked up and placed in the mouse hole. Only the top connection to the coil connector then needed to be made up while the BHA was vertical in the mouse hole and on the critical path of operations.
The re-entry plan was to kick off from a cement plug at approximately 1,750 ft true vertical depth below ground level (TVDBGL) into a relatively soft formation for the area. The plan was then to hold the drilling angle at approximately 7° before building to land horizontally at approximately 2,400 ft TVDBGL. The sidetrack was to be drilled with water only to reduce the use, and therefore cost, of nitrogen in a formation that was not a target. Once the section had been drilled close to the target reservoir, the nitrogen injection would start, underbalancing the well and thereby preventing formation damage from occurring in the reservoir. The drilled section would be left without casing and a pump would be run to lift the well.
After the well had been prepared for the sidetrack, the directional BHA provider and other providers arrived on site and rigged up. The well was kicked off the cement plug. During this process, the BHA was exposed to extreme levels of vibration. Once the kickoff had been established, drilling continued with minimal vibration. A significant advantage of the DCTD tool used in this project is the short length of the BHA; the correspondingly short distance from the bit to the surveying tool, coupled with the ability to survey continuously in real time, means that the steering is very responsive and decisions could be made rapidly.
While drilling the hold section, two significantly productive fractures were intersected. Drilling was stopped, and the well was underbalanced by injecting nitrogen with the water. This gave the operator a simple measure of the productivity of the intersected fractures.
The modeled results were compared with the actual drilling measurements and found to be within 8% of the actual measured result. This should be taken into consideration when working on wells with tight drilling windows.
After the basic well test was completed, drilling continued through the build section. However, a marker formation that was much shallower than expected was observed on the gamma readings. This meant that the trajectory would drop significantly below the top of the target formation. The risk of hitting a water zone was determined to be high, so the operator decided to reduce the sidetrack length rather than drill the full horizontal section. The final section of the well was drilled at a controlled rate of penetration; samples of cuttings were used to determine when the reservoir had been entered. This section was also drilled underbalanced with nitrogen to minimize formation damage.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 189904, “Underbalanced Drilling With Coiled Tubing: A Case Study in Marginal Shallow Wells,” by Adam Miszewski, SPE, and Toni Miszewski, SPE, AnTech, and Peter Hatgelakas, Chuck Henry Energy, prepared for the 2018 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, USA, 27–28 March. The paper has not been peer reviewed.