In the strategic quest for more sustainable and secure gas supplies, operators worldwide are working around the clock to commercially validate and extract unconventional gas resources. This is being done in both deep and shallow plays, using the most efficient and environmentally sustainable methods.
In one Middle Eastern field, attempts to validate unconventional gas resources were faced with numerous challenges. The gas-bearing formations were unconsolidated, increasing hole instability risk, and the constant presence of gas in the mud returns often triggered well control responses from the driller. This led to further increases in the Mud Weight (MW) and resulted in drilling challenges, such as slow rate of penetration (ROP); formation damage; poor logs quality; drilling fluid circulation losses; well control incidents; and differential stuck pipe.
These challenges greatly increased the overall cost of the drilling phase, threatening the economic viability of the project, and limiting the amount of formation evaluation tests that could be made. But even more concerning was the formation damage caused by the high MW that had a drastic impact on the wells’ productivity. Achieving both optimum drilling efficiency and complete formation evaluation in this prospect seemed to be a paradox.
The field’s prospects consist of two potential reservoirs separated by a challenging salt formation that exhibits plastic geomechanical behavior while drilling. This dictated an increase in MW, which in turn damaged the upper reservoir, as it was drilled in the same hole section. The prospects’ formations, themselves, had carbonates interbedded with shale and anhydrite, which complicated the drilling process. This was caused by matrix stress deformation, i.e borehole break-outs challenging the logging operations success and adding to the drilling flat time, due to excessive reaming, treating losses, and managing the Equivalent Circulating Density (ECD).
DRILLING HAZARDS MITIGATION
In an attempt to enhance the drilling economics and come up with a new strategy for the field, one of the world’s leading drilling solutions providers was invited by the operating company to analyze the wells and drilling data, and come up with recommendations. In full collaboration with the operator, the team followed an approach of analyzing the offset wells programs; daily drilling reports; end-of-well report; subsurface data; and field operations reports, aiming at analyzing the onsite drilling team actions, well responses, the decision-making process, and outcomes.
This drilling hazards mitigation process focuses on finding the root causes of drilling problems, identifying the critical causal factors, and applying the right mitigation to address them.
Offset wells analysis. It was observed that drill pipe stuck events happened directly after making drill pipe connections, indicating that the loss of annular friction pressure affected the weak formation, and probably caused a formation collapse; this led to the conclusion that that using a constant bottomhole pressure (CBHP) approach, rather than relying solely on MW, can support the hole and mitigate the hole instability events.
In numerous cases, loss of circulation was observed right after encountering tight spots, the probable cause could be attributed to the restriction in the hole, and the ECD increased to a level that induced losses, and not only the MW, itself. Bit balling also was observed, when the MW exceeded a certain density, reducing the overall drilling efficiency.
It was noticed frequently that an increase in gas reading at surface was recorded after encountering severe circulation losses, sending the well into a losses/kick cycle, and limiting the options available to the driller. In many cases, the only remedy would be to conventionally set cement plugs and re-drill the section. The assumption was made that the ECD can be controlled, then consequently, total losses would be mitigated, and hence, the need for unplanned cement plugs would be eliminated.
Proposed solution. From the above observations, the main cause of most of the drilling challenges was linked to the high MW used, however, any attempt to reduce the MW in conventional drilling would be challenged, because of the geomechanics study recommendations and the fear of having gas at surface.
The salt creeping was a well-known drilling challenge in the pre-salt oil reservoirs,1 where a CBHP variant of Managed Pressure Drilling (MPD) was proven to be successful in mitigating salt creeping.
The proposed solution for the well breathing-ballooning phenomenon is drilling with the lowest possible mud weight in addition to CBHP MPD. This will not only eliminate well breathing, but it also reduces the total amount of gas at surface.
The mentioned drilling challenges affected the log data quality and made it hard to deduce a meaningful prognosis from the target formations and reservoirs. The proposed solution from the team was to use Underbalanced Drilling technology (UBD) to drill the hydrocarbon-bearing formation to reduce formation damage and improve the logs and overall formation evaluation data quality.
These findings and suggested approach built a consensus that a hybrid UBD/MPD solution would offer great advantage to both drilling and reservoir characterization, providing that all risk assessments, equipment design, trainings, operating procedures and contingency plans are in place and fit-for-purpose.
Applying the mentioned solutions would inherently increase the ROP, improving the drilling efficiency and reducing the exposure time on the stability-sensitive zones.
UBD reduces formation damage, enhances well productivity, improves ROP and, in many cases, eliminates drilling fluid losses.2 However, one major challenge was the hole instability.
The answer to the risk of hole instability during UBD operations was adding the fully automated choke manifold to add surface back-pressure and manage the ECD immediately, to support the hole until the MW is increased to safer levels.
Gas produced while drilling is to be measured precisely and flared. This provides the required data to characterize the reservoir by pin-pointing the productive zones and allowing further interpretation to calculate the reservoir permeability. This is aided by conventional formation evaluation techniques that would yield better data quality at lower MW.
Equally important, UBD would validate the existing pressure prognosis, and enable geo-steering to chase the highest productive zone delivering higher productive wells.
MANAGED PRESSURE DRILLING
MPD was to be used only when necessary. It provides the required guarantee for stabilizing the hole geomechanics immediately when it’s in jeopardy, i.e while drilling UBD and getting confirmed symptoms of hole instability. Surface Back Pressure (SBP) is to be applied instantly to increase the ECD, to support the hole and to identify the right MW without overestimation, and hence switching from UBD to MPD as, and only, when needed. Here, the dynamic pore pressure and dynamic formation integrity tests capabilities of MPD come in handy.
Equally important, these capabilities enabled accurate finger-printing of the well behavior to decide the nature of the gas at surface, whether it’s drilled gas, breathed-in gas, connection gas or a true gas kick. These accurate tools empowered the wellsite drilling team to decide the right response without exacerbating any problems.
The full closed-loop drilling of the UBD/MPD set-up, aided by a dedicated mud gas separator, offers safe handling of gas at surface. The equipment to drill both UBD and MPD consists of: rotating control device (RCD), fully automated MPD choke, MPD control system, mud gas separator, nitrogen production unit to aid the safe handling of gas at surface, and valves with an emergency shutdown system, Fig. 1.
MPD is known to be one of the techniques in drilling salt formations, and hence, UBD was to cease before reaching the top of the salt, and CBHP MPD was to commence. Salt instability became even more critical while drilling directionally. MPD, in this aspect, became an enabling technology to access and develop the pre-salt gas reservoirs, using horizontal drilling techniques.
QHSE was a priority, considering the additional equipment, modified procedures, and hydrocarbons handled at surface, and hence, a rigorous training program was designed to serve this purpose, especially on site. This was coupled with comprehensive risk assessment, HAZOP/HAZID, contingency planning, and full procedural review.
IN 8.5-IN. HOLE SECTION
With pore pressure estimates at 86 PCF , UBD mud weight was chosen to be 75 PCF. However, the geomechanics study suggested 100 PCF as the minimum mud weight to support the hole, so there was a need to have SBP to increase the ECD to 100 PCF at any time, to avoid hole collapses, if necessary.
Whenever the on-site drilling team would reach consensus that the hole was starting to show signs of instability, SBP would be applied to increase ECD to 100 PCF by applying 500 psi on the MPD choke, Fig. 2. To aid this precise ECD monitoring and control, the bottomhole assembly (BHA) included pressure-while-drilling (PWD) instruments. The UBD/MPD data control system was linked directly with the MWD system to get real-time data from downhole. This link also provided the means to validate and calibrate the real-time hydraulic modeling system (if needed).
IN 8.5-IN. HOLE SECTION
As the lower part of the 83/8-in. hole section was planned in the salt section, it was decided to switch to MPD just before tagging the salt section. The mud weight also was planned to increase to 97 PCF to support the hole. CBHP MPD was achieved by applying 500 psi on connections, Fig. 3.
This approach did not conflict with the UBD objectives in the upper section, as the reservoir characterization would have been achieved already by inflow testing and pressure building before reaching the salt section.
IN 6-IN. HOLE SECTION
The 6-in. hole section is a pure reservoir section with no salt formation. The reservoir pressure was estimated at 80 PCF, and hence 69 PCF MW was chosen for UBD in this section. However, potential shale streaks would pose a threat on hole stability. The same mitigations and responses of the 83/8-in. hole section were followed in the 6-in. hole section by applying instant SBP control whenever necessary, and by treating the mud system to improve shale inhibition.
The MPD/UBD success in this project helped the operator to better understand the reservoirs and the overlaying formations, and it helped to positively impact future well plans and designs. The UBD/MPD hybrid solution used MW much lower than was stated by the geomechanics study. MPD proved that the excessive MW, in fact, caused more problems than it solved.
Drilling fluid losses, as well as bit-balling problems, were mitigated completely by using the solution provided. CBHP MPD solved the hole pack-off issues in the salt section completely and provided early and precise event identification.
Solving drilling problems like hole instability, losses, bit balling, well control, salt creeping and low ROP by using UBD/MPD opened the door to changing the costly drilling fluid mud to conventional drilling fluid. ROP was enhanced 200% to 300%, compared to offset wells drilled conventionally.
UBD allowed the detection of any gas immediately, hence confirming hydrocarbon presence and providing early formation evaluation. The hybrid UBD/MPD approach added value to the operator by cutting rig time as much as 42% per well, thus enhancing the project’s economics.
In conclusion, the use of the right technology, and in this case the hybrid UBD/MPD solution to address the right challenges, proved to add immense value to this unconventional gas exploration project. It mitigated drilling hazards, improved the safety of operations, and aided the operator in making future drilling campaigns more economically viable.
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