At the beginning of 2021 there were approximately 970,000 active oil wells in the United States and 203,000 in Canada. Historically, most wells in the US and Canada had a single type of lift system installed for the life of the well. The single most common lift system was rod lift. Most wells on land have a rod lift system installed when the well is first drilled and that lift system remains in place for the life of the well (50 years or longer is not uncommon). Over time the size of the rod lift pump might be reduced as the well's production declines, but the type of the lift system remains – rod lift (SPE 2025). There are other fields where the lift system required is not the lift system still in place 3 or 4 years later due to the well's declining output. These wells tend to have the highest fluid output where an ESP is required because the output is greater than 1000 barrels of fluid per day. As time goes by, a lower cost, lower volume lift system will typically be installed – hydraulic lift, plunger lift, or the most common, rod lift. The three most popular types of equipment used on wells today are ESP, Gas (Lift/Injection) and finally Rod Lift. One industry advisor was quoted "When you take into account how many total wells utilize rod lift vs ESP, the hands down winner is rod lift, possibly by something like a 10 to 1 margin. Rod lift is more reliable, cheaper and more loved in the patch. It gets the most votes for the title king of the lift" (Lea 2007). According to research conducted by Spears and Associates more than 20% of all new wells drilled globally will incorporate rod lift (Spears and Associates 2022).
Abstract Managed pressure drilling (MPD) is widely deployed to navigate narrow pore-pressure / fracture-pressure windows, but its highest value in the hostile wells may be interpretive rather than purely controlling. In conflicting pressure regimes, a single surface flow anomaly can be produced by a kick, an isolated loss, wellbore ballooning, or crossflow between incompatible zones, conditions that demand opposite control responses. This paper documents an 8-3/8-in. hole section that exhibited simultaneous loss-and-gain behavior and later developed shut-in pressures exceeding 2,000 psi. Using a closed-loop MPD system maintaining approximately 140–141 pcf equivalent mud weight (EMW) at the casing shoe over a 125–128 pcf base mud, and static MPD pore-pressure tests that identified formation pressure near 137–138 pcf, the crew observed losses that transitioned into gains as flow rate was deliberately reduced. Attempts to raise bottomhole pressure with surface backpressure (SBP) up to about 1,280 psi aggravated losses, and subsequent conventional well-control circulation drove shut-in casing pressure toward approximately 4,700 psi. The multi-parameter MPD signature, flow-out delta from a Coriolis mass flow meter, the response of the anomaly to controlled SBP steps, its dependence on flow rate, pit-volume trend, and returns density, clarified that the dominant mechanism was crossflow rather than a simple kick, isolated loss, or ballooning response. This diagnosis, although reached in a well that had to be completed conventionally, prevented continued misapplication of conventional well-control logic, guided controlled stripping and displacement, and optimized future well planning. The case both demonstrates a practical real-time diagnostic framework and delineates the operational limit of MPD: pressure control alone cannot create a drilling window where none exists, but it can supply the decisive real-time evidence needed for safer decisions.
Abstract Sidetrack drilling in mature fractured carbonate reservoirs often encounters narrow-margin pressure windows because depleted intervals coexist with high-pressure gas zones. Conventional drilling methods in offset wells historically resulted in repeated total loss events and more than 10.5 days of non-productive time (NPT). This study demonstrates an integrated workflow combining managed pressure drilling (MPD) and active wellbore strengthening to safely navigate a 9 pcf (1.2 ppg) pressure window while maintaining well control and formation integrity. A low static mud weight of 75 pcf (10.0 ppg) polymer system was selected to minimize hydrostatic head. At the same time, dynamic surface backpressure was applied to achieve the equivalent mud weight (EMW) of 85 pcf (11.4 ppg) selected from the offset-well pressure response, where this value corresponded to the threshold above which losses initiated. Active wellbore strengthening was implemented through "stress caging" and controlled stress redistribution using sized graphite to seal microfractures and increase fracture initiation pressure. Equivalent circulating density (ECD) was continuously monitored by downhole sensors in the 6-1/8-inches bottom-hole-assembly (BHA) to enable closed-loop pressure control. Cementing parameters were engineered with a dual-slurry design (101 pcf / 13.5 ppg lead and 118 pcf / 15.8 ppg tail) to remain within the hydraulically constrained window established during drilling. The integrated approach enabled loss-free drilling of the lateral section to total depth (TD), maintaining precise pressure control within the 9 pcf (1.2 ppg) margin. By eliminating total losses, the operation saved more than 10.5 days of historical NPT. The primary cement job was completed in a single attempt with zero losses, and post-job evaluations confirmed effective zonal isolation. The results demonstrate that combining dynamic pressure control with geomechanical wellbore strengthening enables successful sidetrack drilling in conditions where conventional drilling methods had previously failed in offset wells of similar geomechanical characteristics. This work demonstrates that MPD can be applied beyond drilling as a means of supporting wellbore strengthening and primary cement placement within narrow operational margins. The combined approach of mechanical pressure control and physical fracture sealing expands the effective operating window and reduces cycle time relative to the conventional approach documented on the offset lateral. By preserving zonal isolation despite narrow geomechanical margins, this methodology offers a candidate framework for future sidetracks in mature, fractured carbonate assets, subject to further validation across additional wells.
Abstract Additive manufacturing (AM) is transitioning from prototyping to qualified production within oil and gas applications operating under high pressure, high temperature (HPHT), sour, and corrosive conditions. This paper examines the current state of AM adoption across upstream applications, identifies the technical and qualification challenges that continue to limit broader implementation, and proposes a practical risk-based qualification framework to support safe and reliable deployment of AM components. The paper consolidates lessons learned from multiple AM qualification and deployment efforts across upstream and surface oil and gas equipment. Emphasis is placed on nickel-based alloys produced via laser powder bed fusion (LPBF) and components exposed to demanding pressure, temperature, and corrosive service environments. Existing industry frameworks, and relevant corrosion and sour-service standards, are reviewed and integrated within a qualification methodology based on component criticality, manufacturing route qualification, and application risks. Different case studies demonstrate how qualification rigor should be scaled according to service severity and the operational consequences of failure. Experience demonstrates that additive manufacturing can meet demanding oil and gas performance requirements when qualification is tailored to the intended application. For operators, the primary risks are not necessarily the AM process itself, but variability associated with supplier capability, manufacturing route, microstructure, and environmental performance. Testing under simulated HPHT and sour-service conditions, including Slow Strain Rate Testing (SSRT) and 90-day Sulfide Stress Cracking (SSC) testing following current NACE/AMPP qualification practices for Alloy 718, demonstrates how established industry qualification methodologies can be applied to validate AM materials for critical service. Standards such as API 20S1 and AWS D20.12 provide a critical foundation for qualified AM production. However, broader adoption will require stronger integration of existing standards into structured, risk-based qualification methodologies that align qualification effort with component criticality and actual service exposure. Rather than relying on a universal qualification approach, qualification activities should be proportional to technical risk while leveraging engineering practices already recognized throughout the industry. This paper provides operators and application engineers with an experience-based perspective on how additive manufacturing can be safely deployed in harsh oil and gas environments. By combining lessons from previous technology adoption, existing industry standards, and industrial qualification case studies, it offers practical guidance for implementing AM using a structured, performance-based qualification philosophy that supports long-term asset reliability, supply chain resilience, and responsible adoption within existing risk management frameworks.
Underbalanced drilling technology in a nutshell contrasts with conventional overbalance drilling due to fact that the bottom hole circulating pressure (BHCP) exerted by the drilling fluid is designed to be intentionally lower than the reservoir pressure. As a result of this pressure imbalance reservoir fluid oil, water or gas (contained within the pore space) is introduced into the wellbore and returns to surface along with the drilling fluid. Where upon the various different fluid streams are separated accordingly. Hydrocarbon gas may be flared off along with any nitrogen (the inert gas injected to lighten the fluid column and induce the underbalance condition). The produced liquid which may contain formation water along with oil will be separated using a 4-phase separator along with the drilled cutting. The cuttings may need to undergo further treatment to remove any residual oil in compliance with any environmental regulatory requirements before they can be adequately disposed of. The base fluid once treated can be reused. [1] Underbalance drilling was deployed across several geographies and interest in this methodology peaked during the 90s where it was combined with new drilling techniques and technologies in the form of horizontal drilling to mitigate common drilling problems such as lost circulation as well as observing productivity improvements. [2] Its use continued across brownfield developments and was deployed across unconventional reservoirs where conventional drilling techniques and reservoir evaluation methods were ineffective. Typical evaluation tools such as logging, coring and seismic that are instrumental across conventional reservoir development and characterization were inadequate in low permeability tight gas reservoirs. A shift to dynamic flow data was needed. Under Balanced Drilling (UBD) by its very essence eliminates any formation impairment uncertainty from the evaluation provided that underbalance condition is maintained throughout operations. [2]
