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Gabaldon, Oscar (Blade Energy Partners, Ltd.) | Gonzalez Luis, Romar (Blade Energy Partners, Ltd.) | Brand, Patrick (Blade Energy Partners, Ltd.) | Saber, Sherif (Blade Energy Partners, Ltd.) | Kozlov, Anton (Blade Energy Partners, Ltd.) | Bacon, William (Blade Energy Partners, Ltd.)
In high pressure high temperature (HPHT) reservoirs and exploratory wells, especially in deep water, there is a higher degree of uncertainty, which can increase the operational costs due to non-productive time (NPT) and operational problems due to the unpredictable nature of these wells. For these challenging wells with narrow windows, Managed Pressure Drilling (MPD) techniques offer cost-effective tools to increase the odds for achieving well and cost objectives assurance. There are significant benefits from early implementation of MPD in the project life cycle. These benefits include from improving operational efficiency to risk mitigation and safety enhancement. However, there is an enormous potential that many operators have been missing. This is related to the incorporation of MPD as a driver in optimizing the well design, which could greatly increase the possibilities of reaching target depth, and potentially prepare to eliminate one or more casing strings. Current well design process hinges on the ability to manage uncertainties by company or regulatory requirements, such as kick tolerance and safety factors. This work addresses the value added from implementing MPD in early stages in the project life cycle through the analysis of case studies. The cost savings from the impact on the well design are also discussed. This work also presents a in depth discussion on the benefits, and enablers of this approach. Furthermore, it presents considerations by taking advantage of dynamic processes facilitated with MPD. Finally, new guiding criteria to aim to constitute a systematic and integrated approach to ensure well integrity and optimize well design while also considering the operational implications and integral cost benefits is proposed to the industry. This paper represents the initial phase of a compressive long-term project to integrate two main components of well design. These are MPD adaptive well design, and statistical analysis based on variations of load and/or strength.
The Spirit River Group in Western Canada has always been difficult to drill and complete due to the presence of natural faulting in shaley formations interbedded with coal. MPD techniques allow the successful drilling of these wells; however, completing these wells has been extremely challenging. On this well, getting liner to bottom without total losses should not have been possible.
To address this, a design that used a three mud system in combination with MPD was utilized. With a diversion sub placed at the heel, the wellbore fluid column consisted of a highly underbalanced drilling fluid in the lateral, a descending column of slightly underbalanced stripping fluid placed in the vertical section, and an overbalanced column of kill fluid backfilled into the annulus from surface.
During the liner run, this three-fluid system design smoothly reduces the hydrostatic pressure at proportional rates to the increase in liner surge. This balances the wellbore at the time the RCD is installed behind the liner. The combination of factors saw full returns to surface during the liner run and, once on bottom, allows the rig to break circulation for the final displacement to completions fluids.
With the successful implementation of this 3-fluid system, the operator was able to drill further, past 22,000’, as it is now possible to run and deploy the liner without expecting the loss of the wellbore's volume of fluid on these tight window wells.
The Austin Chalk is an upper Cretaceous geologic formation in the Gulf Coast region of the United States. For the purpose of this paper, this Austin chalk under consideration is in central Texas. The formation is known for having a wide range in pressure differential, making it difficult to predict the fracture and pore pressure limits on some of the wells. Due to this uncertainty, some operators tend to assume the well problems are related to ballooning/breathing. This assumption leads to drilling issues such as but not limited to stuck pipe, excessive mud losses, and tripping challenges.
With reference to this SPE paper, An operator had encountered some of the mentioned issues above in their previous wells and was looking for a CBHP MPD solution, capable of bridging their internal knowledge gap to becoming MPD aware. MPD was rigged up prior to drilling the horizontal production hole at ±13,000 ft MD. The initial mud weight was 10.5 ppg with MPD maintaining an 11.4 ppge. Later a high-pressure zone was encountered at ±13,500 ft MD requiring 11.6 ppge to control the formation fluid. Drilling continued until ±16,000 ft MD where an 11.5 ppge loss zone was encountered. Therefore this well had no drilling window.
The window stabilized after circulating a few bottoms up with backpressure and lost circulation material. MPD minimized mud losses/gains and helped reach TD safely. At TD, a bigger challenge was how to trip out without swabbing. The Tripping was achieved by placing a heavy pill above the high-pressure gas zone and avoiding the loss zone. When tripping pipe and casing, proper fill was achieved by circulating kill weight mud across the well with MPD. The casing and cementing operation was subsequently conducted and was successfully completed with the utilization of MPD.
Parker, Martyn (Pruitt Tool & Supply Co.) | Seale, Marvin (Red Willow Production Company) | Nauduri, Sagar (Pruitt Tool & Supply Co.) | Abbey, James (Red Willow Production Company) | Seidel, Frank (Seidel Technologies, LLC) | Okeke, Ernest (Pruitt Tool & Supply Co.)
Horizontal drilling in the Fruitland Formation, a Coalbed Methane (CBM) play located in the San Juan Basin (SJB), found across the states of Colorado and New Mexico can present a number of drilling and production challenges. Examples of these challenges include wellbore instability, severe fluid losses, high mud costs, formation damage, and post-well production issues.
Clear fluid brine systems such as Calcium Chloride (CaCl2) and Calcium Bromide (CaBr2) are usually preferred because of their compatibility with coals and their ability to minimize formation damage. However, these brines can instigate fluid losses, cause fluid handling issues, and create long-term production challenges. Coal instability in the horizontal play has historically led to events such as wellbore collapse, stuck pipe, lost Bottomhole Assemblies (BHAs), and challenges such as getting the pipe out of the hole at Total Depth (TD) and subsequently running completions. Ultimately, these problems led to sidetracks, incurring additional costs, time, and resources.
In May 2019, the Constant Bottomhole Pressure (CBHP) technique of Managed Pressure Drilling (MPD) was introduced to mitigate these challenges. Two wells with eight laterals and combined horizontal footage of ±46,000 ft were drilled using CBHP, maintaining 11.4 ±0.1 pound per gallon (ppg) Equivalent Circulating Density (ECD) and Equivalent Static Density (ESD) in the lateral at ±2800 ft True Vertical Depth (TVD). With a focus on safety and training, the mud weight was staged down from 10.8 ppg on the first lateral to 9.8 ppg on the second. The final six laterals were drilled with 8.6 ±0.2 ppg produced water. This paper will detail the planning, training and staged implementation of CBHP MPD with produced water. It will briefly discuss improvement in wellbore stability, cost reduction for drilling laterals, and enhanced production after switching to produced water.
When drilling challenging formations such as very thick highly fractured sour reservoirs or carbonate/karst formations, a lost-circulation zone can be encountered. This causes mud to be lost and gas kick to take place, making the drilling process uncontrollable. Blocking or plugging wide fractures is impossible in many cases, which results in severe safety issues associated with toxic gases.
This study investigates an application of mud cap drilling by injecting foam mixture into the annulus for well control in such harsh conditions. An annular fluid column with foam mixture can be used to prevent kicks and push the toxic gas back into the formation down along the annulus. This foam-assisted mud cap drilling process has been proved to reduce non-productive time and fluid expenses.
This study presents how to model and simulate the process with accurate foam characteristics when foams are used to suppress gas kicks under certain well and fluid conditions. More specifically, this study deals with three scenarios: Base Scenario with a relatively short response time such that the injected foams do not contact the formation gas, and Scenario 1 and 2 with a relatively long response time such that the injected foams interact with the gas, with and without foam coalescence respectively, at the foam/gas interface. The results show how mud-cap drilling parameters (such as pressure, foam density (or, equivalent mud weight), foam velocity, and foam quality) change at different operating conditions and scenarios. Non-Newtonian foam rheology, depending on bubble size and bubble size distribution as modeled by
Solaris Water Midstream has begun operations at its newest large-scale water-reuse complex in New Mexico, the Eddy State Complex. The complex can supply 300,000 B/D of recycled produced water for operators in the northern Delaware Basin. Th complex adds to the company’s ongoing recycling operations at its Lobo Reuse Complex in Eddy County and the Bronco Reuse Complex in Lea County. Two additional water-recycling centers are expected to be completed by December. When all five water-reuse complexes are operating, Solaris Water will have the capacity to recycle more than 900,000 B/D of produced water, with over 3 million bbl of adjacent storage capacity.
Offshore and onshore reliability data (OREDA) gathered by several oil and gas operators for nearly 4 decades is now available online through DNV GL’s data platform, Veracity. The OREDA handbook, established in 1981 in cooperation with the Norwegian Petroleum Directorate, has collected data from almost 300 installations and includes 18,000 equipment units with 43,000 failure and 80,000 maintenance records. The databank also includes information on subsea fields with more than 2,000 years of operating experience. Working in partnership with French IT service provider SATODEV and OREDA member companies, the data were originally presented in a traditional handbook and have been converted to a digital tool called “OREDA@Cloud.” Instigated by a joint industry project (JIP), it allows users to have interactive access to the database.
Pittsburgh-based EQT Corporation announced this week that it is buying Chevron’s properties in the gas-rich Appalachian Basin for $735 million. The deal is inclusive of 350,000 net acres, midstream facilities, and about 550 wells. With a current production mix of 450 MMcfe/D (75% dry gas, 25% liquids), the sale is expected to boost EQT’s total output by 10% upon closing which is slated to take place before year end. EQT said the deal, which includes nearly 120,000 acres in the Marcellus Shale, will be partially financed with cash and credit but the firm has also announced a new equity offering to raise additional funds. He added, “Our unique knowledge of these assets, coupled with our superior operating model, puts these assets in the right hands to maximize the embedded value.”
Another potential hurricane in the Gulf of Mexico (GOM) is on a path toward Louisiana this week, leading oil and gas operators to evacuate offshore facilities and shut in production. Tropical Storm Zeta hit Mexico’s Yucatan Peninsula on Monday as a Category 1 hurricane before it weakened. Zeta is expected to hit Louisiana at or near hurricane strength on Wednesday. The Bureau of Safety and Environmental Enforcement (BSEE) activated its hurricane response team in response to the severe weather. Based on operator reports, BSEE said personnel was evacuated from 154 production platforms (24% of 643 manned GOM platforms) and three nondynamically positioned rigs (30% of 10).
The current presentation date and time shown is a TENTATIVE schedule. The final/confirmed presentation schedule will be notified/available middle of October 2019. If we have learned anything from the North American experience, unconventional resources cannot be exploited by small incremental projects. If we are to be successful in developing these types of reservoirs, we have to make project scale operations work to bring these resources to market in a timely manner. A number of Eastern Hemisphere unconventional gas projects have raised interest, neared completion or are commencing deliveries.