WELL CONTROL / INTERVENTION

Well control during well intervention

PART 1 – Considerations for design and placement of kill weight fluids

To plan a more effective well control program, several important issues must be considered, including the determination of fluid kill-weight, space availability for required fluid tankage and kill fluid pumping schedules

Alex Sas-Jaworsky II, Sas Industries, Inc., Houston

uring the life cycle of a conventional completion, wellbore operations may necessitate hydrostatically balancing the formation pressure to achieve zero surface well pressure. For these types of operations, well control practices described as "kill programs" are employed to replace the resident wellbore fluids with a column of liquid of sufficient density to hydrostatically balance formation pressure. Depending upon the operations to be performed after the well is killed, there are several ways in which well control can be implemented using a variety of fluid rheology types and densities.

Conventional completion designs utilize concentric tubulars assembled to provide desired flow conduits within the wellbore. During installation of the completion equipment, the tubing provides the natural flow path for circulation of pumped fluids from surface. However, once completion tubulars are pressure-isolated downhole using packers or other flow control devices, the circulation pathway from the surface to the completion typically is not available.

If circulation of fluids cannot be established through the completion equipment installed within the wellbore, a well kill pumping technique described as "bullheading" may be used. This well control operation is performed by pumping the kill-weight density liquids through the surface wellhead equipment at a rate sufficient to displace the resident well fluids from the tubulars and back into the exposed completion interval. Although effective, bullhead kills offer minimal control of fluid placement within the wellbore and have a high potential for inducing formation damage. If operations conducted upon completion of the well control program do not require continued service from the completion interval, then formation damage mitigation is not a concern and the bullhead kill method is a viable option.

However, where the well control operation is intended as a temporary pressure balance condition and the exposed completion interval is intended to be returned to production, the design of the well-kill program should focus on achieving hydrostatic pressure balance with a minimum of induced formation damage. In this situation, concentric tube well intervention services have been used successfully to establish the fluids circulation flow path from surface to the completion interval. Using these types of service equipment, the kill operation can be performed by circulating out the resident wellbore fluids and replacing the wellbore volume with a kill-weight liquid having the desired rheology and density for the prescribed service.

Concentric-Tube Well Intervention Services

Well completions are designed with considerations for performing either wireline or tubing-conveyed, through-tubing intervention services within the planned life cycle of the wellbore. Tubing-conveyed, through-tubing well intervention services such as hydraulic workover (HWO) and coiled tubing (CT) are capable of performing a variety of services, with and without surface well pressure present, and are amply suited for pumping and circulating fluids within the completion tubulars. A comparison of these two systems, however, reveals that the well control programs are implemented in different manners.

By design, the HWO system utilizes jointed tubing, which incorporates back-pressure valves in the workstring BHA, and which must interrupt pumping services when making and breaking connections. Implementation of HWO well control operations typically involves deployment of the workstring concentric to the existing completion tubulars, with intermittent pumping down the workstring to fill the pipe and ensure that the ID is free from blockage. The workstring is run to the proposed kill depth, at which time pumping operations are initiated for the purpose of circulating out the resident well fluids with the kill-weight fluid designed to achieve pressure balance.

The kill program is typically conducted with the HWO workstring stationary, and once hydrostatic pressure balance is achieved, fluid circulation is halted and the workstring is extracted from the wellbore. During workstring extraction, the kill-weight fluid pumping operation generally is directed into the flowcross within the well control stack, maintaining the fluid column height in the annulus.

In contrast, CT services utilize a continuous-length tubing string, which can be deployed and retrieved throughout the prescribed operation without interrupting pumping. The continuous-pumping capability of CT affords a greater degree of fluid placement control within the wellbore and allows variations to standard kill programs to achieve the desired hydrostatic pressure balance. The CT string can be deployed and retrieved rapidly in comparison to HWO systems, reducing the time needed to perform the desired well control service. In addition, with the introduction of higher yield strength grades of CT, the upper pressure limits for safely performing CT services has increased dramatically.

Although the continuous-length CT product offers benefits in reduced service time and fluids placement over HWO systems, CT has a finite service life due to bend-cycle fatigue that occurs as a consequence of the CT operation. Therefore, it is recommended that the user obtain the life management log for the designated CT string (with the prediction for remaining service life) from the CT vendor prior to dispatching the equipment.

Pre-Job Planning And Well Control Review

Prior to implementing concentric tube well control operations, several issues must be addressed to define the nature of the kill operation, assess the risk factors and determine the most appropriate method for implementing the desired kill. Unlike well control contingency planning for drilling or completion operations, the level and quality of job-critical information available on location is typically insufficient to effectively implement well kill operations in a safe and prudent manner. Therefore, when preparing to perform through-tubing well control operations, a dedicated effort must be made to obtain the most reliable information regarding wellbore design and condition, as well as formation pressure and completion integrity before dispatching the well intervention equipment to location.

Completion details and wellbore orientation. Proper design of any concentric-tubing well control operation requires that wellbore completion information and borehole orientation be fully incorporated into the well control plan, Fig. 1. The wellbore schematic for a given completion should provide information on the type and size of the wellhead tree connection and sizes of tubular goods installed in the wellbore, along with recorded setting depths.

Fig. 1. Wellbore completion information and borehole orientation are key to the proper design of concentric-tubing well control operations. Schematic should include type and size of wellhead tree connection, sizes of tubular goods installed and recorded setting depths.

The measured depth (MD) values reflect the tubing tally records provided in the completion detail and are needed to calculate fill-up volumes for the flow-path conduit from the completion interval to surface. Of greater importance, however, is the corresponding depth value shown as true vertical depth (TVD). TVD measurements are required to calculate hydrostatic pressure exerted on the formation from a standing column of fluid of a given density. Therefore, proper well control planning requires that all completion tubular design components and reservoir depth measurements be reported in both MD and TVD values.

The aforementioned MD and TVD measurements are referenced from the rig floor, typically referred to as KB. Depending upon how and where the wellbore was drilled, the values for KB may be reported as distance from ground level (onshore) or distance from an installed component located on the wellbore structure (e.g., tubing hanger, lowest most flange, etc.). With the exception of concentric-tubing operations performed from the rig floor, depths must be corrected to the given reference to ensure that the workstring depth readings can be correlated back to MD and TVD positions within the wellbore.

Fluid hydrostatics and pressure balance concerns. Prior to commencing any well control operation, the kill-weight fluid density needed to balance the formation pressure must be determined. The equation commonly used to calculate fluid density r (ppg) to balance a given pressure P (psig) with a true vertical fluid column height H_Hyd (ft) is given below:

This calculation provides the user with a value equal to the "average" fluid density needed to balance the given reservoir pressure with a standing column of the fluid to a specified TVD. The fluid column height measurement in this calculation must be corrected for differences with KB measurements and reflect the point in the surface production tree or well control stack where the top of the kill-weight fluid column will be located. In general, the top-of-column point should be located within the surface production tree, which ensures that the desired hydrostatic pressure balance is maintained at the wellhead after the service riser and well control stack are removed.

However, rig-up for a prescribed well intervention service may locate the returns circulation port in the well control stack riser at a point significantly higher than the surface tree. In this situation, the primary kill-weight fluid circulation program may need to locate the top-of-column point at the returns line elevation, with secondary kill contingencies prepared for placing the kill-weight fluid column top at the desired location in the surface production tree.

Attention also should be paid to the predicted change in kill-weight fluid density due to changes in temperature and pressure within the wellbore. Fluid density decreases with an increase in temperature and increases with an increase in pressure. Further, the change in fluid density due to temperature and pressure depends upon the fluid chemistry and amount of dissolved or suspended solids in the fluid.

Since the "average" fluid density calculated in the above equation does not account for fluid property changes due to temperature and pressure conditions, this value should be used only as a reference density when selecting the desired kill-weight fluid. Once the kill-weight fluid type is identified, the fluid supplier should provide a recommended blending density for surface conditions that yields the desired hydrostatic pressure balance at the specified fluid column TVD when the fluid reaches equilibrium temperature within the wellbore.

An example of the change in fluid density due to temperature and pressure for given wellbore conditions is seen in Fig. 2. In this example, the "average" kill-weight fluid density needed to balance the 5,200-psig reservoir pressure is calculated to be 10 ppg. As such, the blended CaCl₂ kill-weight fluid must yield an apparent density of 10.15 ppg at 74°F to achieve an "average" kill-weight density of 10 ppg at the temperatures and hydrostatic pressures seen in the example wellbore.

Fig. 2. This example illustrates the change in fluid density due to temperature and pressure for given wellbore conditions. The average kill-weight fluid density needed to balance the 5,200-psig reservoir pressure is 10 ppg. The blended CaCl2 kill-weight fluid must yield an apparent density of 10.15 ppg at 74°F to achieve an average kill-weight density of 10 ppg under the temperature and pressure in the example.

Therefore, kill-weight fluid density must be adjusted for the surface mixing temperature to obtain the desired density at wellbore temperatures. When salt solutions are selected, the crystallization point of the specified-density fluid must be known and compared to the projected temperature profiles expected during the well control pumping program to ensure that the fluid temperature cannot fall below the crystallization point.

Formation damage concerns. Once the appropriate kill-weight fluid density is calculated for the given well conditions, an assessment should be made as to type and rheology of kill-weight fluid to be selected. If formation damage and/or return permeability is not a concern in the well control program, then a colloidal kill-weight mud system can be considered. The mud system, which may be either water-or oil-based, can be blended to the desired fluid density with suspended solids to achieve the required kill-weight.

By design, colloidal mud systems form a filter cake across a permeable formation, essentially creating a barrier to fluid losses. Although these mud systems are very effective kill-weight fluid candidates, the damage to the formation, which typically accompanies their use, is undesirable.

If the formation exposed to the wellbore during the kill program is expected to be returned to production, the kill-weight fluid selection process should include a review of fluids that offer minimal consequential formation damage and high return permeability. Typically, these fluids are in a class of liquids described as high-density brines, which behave as clear-penetrating liquids when placed across permeable formations. As a result, kill-weight fluid losses to the formation can be expected when high-density brines are used.

The volume of fluid loss depends upon the amount of excess annulus pressure applied, either as back pressure from the surface choke program or from frictional pressure losses developed within the annuli during the circulation program. When considering the use of high-density brines for kill-weight fluids, it is also important to determine their chemical compatibility with formation fluids to ensure that no secondary emulsions or adverse precipitation of solids will occur as a result of the dissimilar fluid contact. Further, mitigation of formation damage is more effective when the high-density, clear-penetrating brines are filtered prior to circulation within the wellbore.

Surface fluid tankage requirements. The proposed kill-weight fluid chemistry and rheology should be compared with the chemistry and rheology of fluids available on site to determine whether the two fluid systems are compatible. For example, if the typically pumped treatment fluid is of a chemistry or rheology where blending to achieve kill-weight density is not possible or desirable, then plans must be made to mobilize additional tankage to transport and/or blend a completely separate volume of kill-weight fluid. The assessment of minimum tankage volume needed to prepare a kill-weight fluid circulation program must include the internal volume capacity of the workstring, internal volume capacity of all exposed completion tubulars within the wellbore and the estimated volume of kill-weight fluids lost to the exposed formation when performing the circulation kill program.

Depending upon the sophistication of the kill-weight fluid mixing program, it may be desirable to batch-blend in 20- to 35-bbl volumes to accommodate limited space availability on location. In high-density, clear brine kill programs, brine is typically expensive and will most likely be pre-mixed at the fluid supplier facility. As such, onsite space accommodations for the tankage needed to transport the required volume of kill-weight fluid must be addressed.

Further, contingencies must be prepared for capture of the fluid volumes to be circulated out of the wellbore. If it is not possible or desirable to displace the existing wellbore fluids to the production system, then additional tankage will be needed to capture the volume of contaminated or displaced fluids from within the wellbore tubulars. This volume must accommodate the internal capacity of exposed completion tubulars within the wellbore and include additional fluid volume gained in the form of influx occurring during the fluid circulation program. Onsite space limitations for surface fluid tankage must be addressed before equipment is dispatched to ensure that the required fluid volumes can be provided to location before operations commence.

Well control choke pressure schedule. Once the circulation well kill method is selected and operating parameters critical to proper implementation are determined, the surface choke pressure schedule must be prepared. This schedule is designed to impose a desired surface pressure onto the wellbore annuli to ensure that a constant bottomhole pressure (CBP) is maintained during the kill-weight fluid circulation program.

For conventional circulation kill programs, the total calculated volume of kill fluid needed to fill the wellbore annuli is divided by ten, which allows the user to prepare a volumetric displacement schedule in ten equal stages. Each volume stage circulated into the wellbore represents an increase in kill-weight fluid column height within the annuli, yielding an increase in hydrostatic pressure acting on the exposed formation interval.

Note that the predicted MD for the top of each kill-weight fluid stage in the wellbore annuli must be corrected to TVD measurements. Based on the corrected vertical height of the kill-fluid / resident fluid interface, the increases in hydrostatic pressure acting on the formation must be compensated by a corresponding decrease in surface choke pressure. From this wellbore annuli fill-up schedule, a surface-choke-pressure adjustment schedule can be prepared wherein uniform decreases in surface choke pressure are made for each stage of kill-weight fluid pumped.

For well configurations with minimal ID bore changes, this practice provides a reasonably accurate means for predicting the choke pressure adjustments for maintaining CBP with uniform stages pumped. However, well control operations conducted concentric to existing completion tubulars typically deal with multiple ID bore changes, making the uniform ten-stage surface choke schedule format inappropriate for CBP kill programs. With the variations in annuli geometry for multiple ID bore completions, the fluid height attained within the annuli on a pumped-stage basis does not yield the predicted hydrostatic pressure increases, significantly altering the CBP well control program.

In the following example, a concentric tubing fluid circulation kill program is to be conducted within a well having 2-7/8-in. OD production tubing (2.441-in. ID) set at a depth of 9,440 ft MD (9.440 ft TVD). Below the packer setting depth is a segment of 7-in. OD (6.184-in. ID) casing, with the completion interval top located at a depth of 10,000 ft MD (10,000 ft TVD), Fig. 3. The estimated formation pressure for this completion interval is 5,200 psig. Assuming a 1.25-in. OD coiled tubing workstring is run within this wellbore, the proposed circulation program requires 60 bbl of kill fluid to fill the casing and tubing annulus from the top of the exposed completion interval to the surface returns point in the riser. The casing annulus interval is 560 ft in height and requires approximately 20 bbl to fill. The remaining 40 bbl are required to fill the 9,440 ft of production tube annulus.

Fig. 3. Assuming 1.25-in. OD coiled tubing is run into this wellbore, the proposed circulation program requires 60 bbl of kill fluid to fill casing / tubing annulus from the top of the exposed completion interval to the surface returns point in the riser. Casing annulus interval is 560 ft and requires about 20 bbl to fill. Remaining 40 bbl are required to fill the 9,440 ft of production tube annulus.

With a recorded shut-in tubing pressure of 1,000 psig, the conventional surface-choke-pressure schedule would be divided into ten equal stages, with each stage comprised of a 6-bbl volume of kill fluid. Following this program outline, the surface choke pressure schedule would reduce the choke pressure by 100 psig per stage, Fig. 4. However, due to the significant differences in fill-up volume between the production tube and casing annuli for this example wellbore, this schedule would create an underbalanced pressure condition early in the kill program, causing formation fluid influx and compromising the well control program.

Fig. 4. With shut-in tubing pressure of 1,000 psig, the conventional surface-choke-pressure schedule would be divided into ten, 6-bbl kill fluid stages. However, due to significant differences in fill-up volume between production tube and casing annuli for this example, an underbalanced pressure condition would be created early in the kill program.

Therefore, a separate choke pressure schedule should be prepared for both the production tube annulus and the casing annulus. A comparison of the conventional and recommended surface choke pressure schedules for this example is shown in Table 1 and illustrates how an underbalanced condition of about 250 psig can be created if the conventional surface-choke-pressure schedule is used. To ensure that the surface-choke-pressure schedule properly accounts for the actual increase in hydrostatic pressure resulting from the fill-up volume stages, each change in annulus geometry should be evaluated separately to determine the corrected bottomhole pressure. 

Bibliography

World Oil’s Coiled Tubing Handbook, 3rd Edition, Gulf Publishing Co., Houston, TX, 1998.

Sas-Jaworsky, A., and Ali Ghalambor, "Considerations for Conducting Coiled Tubing Well Control Operations to Minimize Formation Impairment," SPE Paper 58792, presented at 2000 SPE International Symposium on Formation Damage Control, Lafayette, LA, February 2000.

Sas-Jaworsky, A., "Practical Considerations for Enhancing Coiled Tubing Well Control Operations," SPE Paper 60739, presented at the 2000 SPE/ICoTA Coiled Tubing Roundtable, Houston, TX, April 2000.

Well Control School, Guide to Blowout Prevention, WCS First Edition, New Orleans, LA, 2000.

Coming installments:

Part 2 – Practical application of through-tubing well control operations.

Part 3 – Well control pumping options to minimize induced formation damage.

Part 4 – Proper selection of coiled tubing surface and downhole well control equipment.

The author
	Alexander Sas-Jaworsky II is founder and principal engineer of SAS Industries, Inc., formed in 1995 and specializing in mechanical testing, training and service consultation for all aspects of applied coiled tubing technology. He began his career with Conoco after receiving a BS degree in petroleum engineering at the University of Southwestern Louisiana in 1982, and he worked for various coiled tubing companies before and while attending college. He worked in several Conoco divisions as a production engineer before transferring to the Conoco Houston Production Technology group in December 1990 as worldwide concentric workover consultant for coiled tubing and snubbing. He is a registered professional engineer in Louisiana and Texas, SPE member, and serves on API committee 3/subcommittee16 as chairman of the well intervention well control task group.

Part 2

Part 3

Part 4

Part 5