Drilling Cost Management

Rethinking Drilling & Blasting: Tech-Driven Cost Optimization In the drilling and blasting process, we often focus primarily on the blasting phase—assuming that drill hole marking and execution have been done correctly. However, field realities are often different. Challenges like uneven bench free faces, manual marking errors, and gradient-based depth selection frequently lead to suboptimal outcomes. Through multiple field case studies, I observed that these issues are common and contribute significantly to increased operational costs. To better understand this, I analyzed 15 blasts. For each one, we used drone surveys post-design to evaluate KPIs and compared them against our planning software. The insights were eye-opening—technology adoption alone enabled a 10–15% cost reduction, with no additional research investment required. We also optimized explosive usage by reducing the number of holes, further enhancing efficiency. Key takeaway: Smart tech integration in drilling and blasting can lead to substantial cost savings and process improvements—without needing to reinvent the wheel. 🔍 If anyone is interested in my case study presentation, feel free to reach out. I’ll be happy to share the full process and field KPIs we used.

Lessons from OpEx, CapEx, RevEx, and FinEx in Oil & Gas I thought the biggest challenges were always technical: drilling deeper wells, optimizing completions, or handling production declines. But over time, I realized something surprising—sometimes the biggest challenge isn’t the well, but the cost behind it. In oil & gas, four types of costs shape everything we do: OpEx (Operating Expenditure) CapEx (Capital Expenditure) RevEx (Revenue Expenditure) FinEx (Finance Expenditure) Let me share why these four matter, with lessons I’ve seen play out in our industry. OpEx – the survival game during downturns During the 2014 oil price crash, I remember how every operator suddenly turned their eyes to OpEx. Fuel costs, chemical usage, maintenance schedules—nothing escaped scrutiny. Why? Because when oil drops from $100 to $40 per barrel, survival depends on squeezing every bit of efficiency from operations. I saw teams innovating—recycling water, optimizing lift systems, renegotiating service contracts—just to keep fields alive. That’s the power of OpEx management. CapEx – the long bets that can make or break companies CapEx is where oil & gas lives and dies. Building pipelines, drilling new exploration wells, investing in FPSOs or LNG trains—these are billion-dollar bets. But sometimes, timing is everything. I recall projects sanctioned at peak oil prices that later became stranded assets when the market collapsed. On the other hand, companies that timed CapEx wisely, entering new basins when costs were low, gained advantages for decades. CapEx teaches us: not every shiny project deserves greenlight. ROI and risk analysis matter more than enthusiasm. RevEx – the “invisible” costs behind every barrel In 2020, when the pandemic hit and demand collapsed, many companies realized that their cost per barrel wasn’t sustainable. Workovers, transport fees, storage costs, sales commissions—all piled up. Some operators scaled back RevEx aggressively, focusing only on wells with the best economics. Others learned the hard way: producing barrels that don’t cover variable costs only burns cash. RevEx reminds us that efficiency isn’t just technical—it’s economic. FinEx – the hidden weight of money Oil & gas is capital-intensive, and financing is inevitable. But I’ve seen cases where high debt and unfavorable loan terms turned into chains. When oil prices fell, some companies weren’t brought down by geology or technology, but by FinEx—interest rates, refinancing risks, and debt servicing. On the flip side, firms with strong balance sheets and smart financing emerged stronger, even acquiring distressed assets during downturns. Managing FinEx well can turn crisis into opportunity. The best companies aren’t just those with giant discoveries or record-breaking wells. They’re the ones that know when to cut OpEx, how to time CapEx, where to optimize RevEx, and how to structure FinEx. #OilAndGas #Energy #Finance #OpEx #CapEx #RevEx #FinEx #Resilience #BusinessStrategy

The Impact of LGS and HGS on Drilling Efficiency and the Role of Solids Control Equipment In drilling operations, maintaining the right balance of low-gravity solids (LGS) and high-gravity solids (HGS) in the drilling fluid is essential for efficiency, cost control, and safety. Here's a closer look at their impact and how solids control equipment enhances performance: Understanding LGS and HGS Low-Gravity Solids (LGS): These are typically drill cuttings, clays, and fine particles with a specific gravity below 2.6. Accumulation of LGS in the drilling mud can lead to increased viscosity, reduced drilling rate, and higher equipment wear. High-Gravity Solids (HGS): These are barite or other weighting agents added to maintain mud density. Managing HGS ensures proper pressure control and stability in the borehole. Challenges of Unbalanced Solids High LGS Content: Can reduce mud rheology and cause excessive wear on pumps and bits, slowing operations. Insufficient HGS Management: Results in ineffective wellbore pressure control, risking blowouts or wellbore collapse. Optimal Solids Control: The Key to Efficiency The role of solids control equipment is critical in achieving the right balance of LGS and HGS while maintaining mud properties. Here's how it works: 1. Shale Shakers: Remove larger cuttings, minimizing LGS accumulation early in the process. 2. Hydrocyclones and Desanders/Desilters: Separate finer particles that could increase fluid viscosity and reduce efficiency. 3. Decanter Centrifuges: Provide precise control of ultra-fine particles and help recover barite, reducing HGS loss and operational costs. Quantifiable Benefits of Effective Solids Control Reduced Dilution Costs: Efficient equipment lowers the need for mud dilution, saving up to 30% on fluid costs. Increased ROP (Rate of Penetration): By minimizing solids content, the ROP can improve by up to 20-30%, depending on formation conditions. Lower Maintenance Costs: Proper solids management decreases wear on pumps and bits, reducing downtime and repair expenses by 15-20%. Conclusion Investing in high-performance solids control equipment is not just a necessity; it's a strategic advantage. By managing LGS and HGS effectively, drilling operations can achieve optimal fluid performance, improve wellbore stability, and significantly reduce operational costs. Effective solids control is the cornerstone of efficient, safe, and cost-effective drilling

The Law of Diminishing Returns in Drilling There's a dangerous misconception in mineral exploration, a kind of brute-force logic that says 'more is always better.' You have an Inferred volume, and the thinking is if you just throw enough metres at it, you'll magically convert it all to Indicated and maybe Measured. But it's not a straight line. It's not even close. Humans like linear relationships, in reality, the more you drill a given volume of rock, the less you get back for every dollar you spend. It’s the classic law of diminishing returns, and ignoring it is one of the fastest ways to burn through your treasury with little to show for your “investment”. Look at this chart. We call it the Investment Curve, and it tells a story that every single person holding a purse string in this industry needs to understand. On the left, things look great. You spend a little, you get a lot. For this particular project, the first 2,750 metres of planned drilling gets you a massive 75% conversion of your target blocks. That’s fantastic bang for your buck. Your initial investment is working hard, and you're rapidly derisking the your asset. Everyone is happy. Look what happens as you move to the right. To get the *next* 10% gain, taking you from roughly 75% to 85%, you have to drill an additional 4,000 metres. You've just spent almost double the metres for a fraction of the gain you got at the start. And it gets worse. To get from 85% to over 90%? That's another 2,750 meters. The curve is flattening out. You’re investing bad money after good, chasing a level of geological certainty that the market simply does not care about and that your project economics likely don't require - at least not at this stage. It’s a business and trade off problem, not a geological one. It forces the most fundamental question every exploration manager and CEO has to face: When do you move the drill rig to generate more value per metre drilled? At some point, the opportunity cost of continuing your infill program becomes astronomical. The millions of dollars you're spending to grind out that last, stubborn 5% of resource conversion could be used to drill an entirely new exploration target. A target that, with a single hole, could rerate your company's stock overnight, something your infill program, no matter how successful, will rarely if ever do. Although critical infill just does not excite the market. This chart is the antidote to lazy thinking. It replaces the "drill it till it's all classified" mentality with a sharp, strategic question: What is the optimal point on this curve to stop investing here and start investing somewhere else? It’s about making an informed, data-driven decision, not just drilling for the sake of geological/philosophical perfection. It's about understanding that your drill rigs are capital allocation tools, and your job is to deploy them where they can generate the highest possible return for your shareholders.

I’ve worked with a lot of drilling engineers, supers, and company men over the years. When I ask about their impact, most of them shrug and say: “I get the well from spud to TD.” Here’s the truth: drilling isn’t just making hole. The difference-makers are the ones who beat the curve, bring wells in under AFE, and keep crews safe while holding schedule. One client of mine shaved 36 hours off a rig move. He thought it was nothing special. On paper, we reframed it as $1.5MM saved per move — and that got him multiple callbacks with operators. Tips for drilling pros updating resumes or LinkedIn: ➤ Go beyond depth drilled — show how you cut flat time, tripping hours, or improved ROP. ➤ If you’ve tested new BHAs, mud systems, or bits, explain the performance gains in real numbers. ➤ Tie your results to AFE and schedule — “delivered ahead of curve” or “brought in $X under budget” speaks volumes. ➤ Safety is never just assumed — zero incidents across a campaign is a career highlight, not background noise. From spud to TD, the story isn’t footage drilled. It’s time, cost, and safety delivered better than planned. #oilgas #oilandgas #engineering #drilling

🚀 Drilling Without Returns: Lessons from Colombia’s Piedemonte. Managing severe lost circulation is one of the toughest challenges in drilling. At the Piedemonte fields in Colombia, operators faced massive losses exceeding 130,000 bbl while drilling a 26” section in Pauto M4. The result: long non-productive time, high fluid costs, and community issues due to excessive water usage and logistics. But by applying an integral strategy in Pauto M5, the outcome was radically different: ~157,000 bbl lost but with zero NPT for water supply. 14 days faster than planned. USD 0.96 MM saved compared to the previous well. No HSE incidents or community conflicts. Compliance with environmental license limits. The key? ✔️ Early planning of water storage and logistics. ✔️ Use of inhibited water with 0.35 lb/bbl PHPA polymers. ✔️ High-viscosity/asphalt pills for stability and hole cleaning. ✔️ Close coordination with the community. This case shows that in high-risk drilling environments, success depends less on “fighting” losses and more on strategic adaptation and logistics. The lessons learned even opened the door for aerated fluids and MPD solutions in future wells. 👉 A reminder that innovation in drilling is not always about new tools, but about how we rethink operations to turn challenges into efficiencies

Closed Loop System Results in 21% Cost Reduction on 13,000 ft Well A customer approached us seeking ways to reduce both disposal and drilling fluid costs. They had just completed a 13,000 ft well using traditional methods and were looking to implement a complete closed loop system on their next well. Coincidentally, we had recently installed our closed loop system and completed a nearly identical 13,000 ft well. After compiling and analyzing all operational data, the results were clear: a 21% cost reduction was achieved on the second well. This reduction was driven by: Lower disposal volumes, thanks to efficient solids control and fluid recovery Improved mud retention, minimizing the need for additional mud products Streamlined waste handling, reducing haul-off frequency and associated logistics costs These results highlight the significant value a properly executed closed loop system can provide—both environmentally and financially.

Total Drilling Cost: The Metric That Quietly Makes or Breaks Your Mine Consequent to a previous article, we have been asked to discuss briefly the financial implications of poor drilling. When we talk about drill and blast, the conversation usually leans towards explosives and their application, while the drilling component gets far less attention. Many operations still track drilling the way they always have: cost per metre drilled. It’s neat. It’s familiar, yet it’s dangerously incomplete. Drilling doesn’t exist in isolation. Every metre drilled sets the conditions for blast performance, downstream productivity, and ultimately profitability. When drilling is optimised solely to reduce the drill contractor’s invoice, costs are often pushed—quietly but significantly—into every stage that follows. That’s why Total Drilling Cost matters far more than drill cost alone. What Is TDC (Really)? Total drilling cost is not just: Drill contractor rates Consumables Maintenance Fuel and labour It also includes the consequences of drilling quality: Hole deviation and collar accuracy Burden and spacing variability Sub-drill consistency Redrilling Misfires and blast inefficiencies Poor fragmentation impacting loading, hauling,crushing Increased dilution, losses, or downstream bottlenecks A cheap metre drilled badly is one of the most expensive metres you’ll ever mine. The False Economy of “Cheap Drilling” We've seen this pattern repeatedly: Drill rates are pushed down Penetration rate becomes the primary KPI QA/QC is reduced Operators are incentivised on metres, not quality On paper, drilling cost improves. In reality: Blast performance becomes inconsistent Powder factor increases to compensate Dig rates slow Crusher throughput drops Maintenance costs rise Reconciliation gaps widen The operation spends far more trying to fix the blast than it saved on drilling. Shifting the Conversation: From Cost to Value High-performing operations look at drilling differently: Cost per effective hole, not cost per metre Accuracy compliance, not production metres Drill-to-blast alignment, not isolated KPIs System performance, not departmental optimisation They understand that drilling is a precision activity, not a volume race. What to Measure Instead If you want to understand your true drilling cost, ask: How much rework are we carrying due to poor hole placement? What is the variance between planned and achieved burden? How often do blast designs require modification to compensate for drilling? What is the downstream cost of poor fragmentation? Are drill KPIs aligned with blast outcomes—or working against them? These answers rarely sit in one department. Final Thought Drilling is the first act in value creation. Get it right, and everything downstream becomes easier. Get it wrong, and no amount of blasting “optimisation” will save you. If you’re still judging drilling purely on cost per metre, you’re likely paying far more than you think.