How to Improve Well Performance

Real Field Trends in Directional Drilling Directional drilling today is not just about hitting the target. Anyone can land in the zone on paper. The real challenge in the field is increasing ROP while protecting wellbore quality and maintaining geometric integrity. One of the biggest trends I see is the push to reduce slide time. Not just for efficiency, but because too much sliding destroys well quality. Slide intervals create micro-doglegs, irregular curvature, and additional torque & drag that later show up during casing and completion. You may hit target but you leave problems behind. With conventional motors, the real variable is not theoretical toolface. It is effective toolface under load. Downhole response is affected by: • Reactive motor torque • String torsional wind-up • True weight transfer to the bit • Formation push • Nominal bend vs effective bend under dynamic conditions The toolface you set at surface is not always the toolface working at bottom. If you do not understand that angular loss and mechanical interaction, you end up chasing corrections, increasing tortuosity and degrading well quality. Another strong field trend is the integration of drilling dysfunction analysis into directional decisions. We are not just watching surveys anymore. We are monitoring: • Torsional stick-slip • Axial vibration • Lateral vibration • Shock loading These directly affect directional performance. High lateral vibration reduces build efficiency. Torsional instability impacts motor output consistency. DLS predictability depends on BHA stability. Mechanical Specific Energy (MSE) is also becoming a practical indicator in real time. When MSE increases without ROP gain, something is happening either formation change or inefficient energy transfer. Both will affect directional response whether you acknowledge it or not. In aggressive curve sections, DLS is no longer just an average number per 100 ft. The 3D smoothness of the well path matters. Local curvature concentrations create fatigue points and long-term torque & drag penalties. Hitting target is not enough. The well has to be drillable, runnable, and productive. Digital tools and predictive models are improving, but they do not replace field understanding. Formation variability and dynamic downhole mechanics still require interpretation and experience. Closing Perspective Technology is advancing. Expectations are increasing. Margins for error are shrinking. But the wells that consistently perform are drilled by people who understand downhole mechanics not just by software. Directional drilling today is mechanical system control under dynamic conditions. We are either managing the interaction between WOB, torque, bend geometry, formation behavior, and wellbore curvature… Or we are reacting to it.

For Nigeria's Project 3M bopd, instead of defaulting to: -Drilling more wells -Increasing interventions Operators should first ask: -Are we operating at optimal network conditions? -Which wells are constraining the system? -Can selective shut-ins or choke optimisation unlock hidden capacity? Today, during our retreat, I shared a case example with my colleagues from a project on integrated production system modelling (IPSM) I did over 10 years ago. Here, four oil wells were producing into a common manifold and one of the wells was shut in and "unexpectedly", total production increased by almost a thousand barrels per day? This appeared counterintuitive at first glance. How can producing from fewer wells result in higher output? This is where integrated production system modelling and analytics come in. With the right tools and expertise, operators can: -Diagnose system constraints -Simulate alternative operating scenarios -Unlock production without additional CAPEX When multiple wells produce into a shared system, they don’t operate independently. They interact through flowlines and manifolds. Each additional well contributes to system backpressure, which in turn increases flowing wellhead pressure and reduces drawdown. By shutting in one well, the system experiences: -Reduced backpressure, -Increased drawdown for the remaining wells. -Improved flow conditions This of course leads to increased production. In many assets, especially where infrastructure is constrained, one poorly performing or high-backpressure well can penalise the entire network/system. This is the reason why CypherCrescent Limited recommend integrated production system modeling as a foundational option before well intervention and drilling. It is interesting that most of the operators in Africa still do not prioritize integrated production system modelling before well intervention decisions are made. I’m a strong advocate of well intervention but before we intervene, we must first get the fundamentals right through proper system housekeeping

Most teams move on quickly after projects without taking time to reflect. One of the most powerful ways to improve performance is surprisingly simple: a thoughtful debrief. Debriefs help you turn experiences into progress. Here are three principles that make them effective. ✅Debrief Every Key Project Review what worked, what didn't, and what you'll do differently next time. ✅Set Behavior-Based Goals Replace vague goals like "try harder" with clear actions that improve performance. ✅Treat It All as Data Don't take results personally. Analyze what happened and adjust the process. The best teams don't succeed because they never make mistakes. They succeed because they learn faster than everyone else. 📌 Save this post so you remember these 3 ways to turn experience into progress.