In a Downturn Market….
In today’s market of ultra-low oil prices, if you are still drilling, optimization of your drilling program should be/could be your missing link. We are now in a time of uncertainty that is setting records, and they aren’t good records. Rig counts are at all-time lows. If you are one of the few brave companies gutting it out during the slump and still drilling ahead, you are faced with some difficult decisions. Where do I cut cost? What cost can I cut without sacrificing performance? Do we even continue the drilling program? One option that few companies even ponder is spending money! How can you safely spend money and take on a new addition to overhead in such a market? Honestly, it’s quite simple. You should be focused and or have someone solely focused on drilling optimization from head to toe.
Can you trip faster? It depends, have you run surge swab modeling to see? Odds are one of the two: You could be either tripping too fast and causing some of your stability issues by swabbing/surging and breaking down the formation OR you are tripping too slow and wasting valuable rig time by being overly cautious.
Do you have the correct hydraulic horsepower for your directional setup? Are you seeing washout and or housing roll in softer formations? Again, model and plan for your drilling project to assure that you have exactly what YOU need. Long gone are the days of “feel” on a drilling rig. Modern drilling rigs are predominately joy sticks and there is no “feel”. With this, the connection times are far extended from the days of Kelley rigs where the blocks never stopped. In this safety consumed culture, we have had to sacrifice time on certain ops, specifically connection time.
Are your drilling parameters suited best for YOUR needs? Again, parameters should be based on sound engineering and not “feel”. You simply cannot feel a highly deviated hole until it is far too late. Subtle changes in an ERD well call for changes to be made sooner than later. By the time you feel it, you are more than likely stuck or well on your way to being stuck. Remember, weights and ECD don’t change much in an ERD well.
As an industry, we for the most part have not evolved past the days of vertical wellbore feel and what we once knew to be fact. ERD wells are a totally different animal and as such should be treated so. What we hear the most as ERD professionals is somewhere along the lines of; “We have been drilling these wells for 40 years without engineers”… This couldn’t be farther from the truth. True ERD wells with a high step out ratio have been drilled for 15-20 years maximum and all of them that were successful were highly engineered. What this tells you is that ERD engineers with 15-20 years of experience have more experience than ANY employee on your roster. While Jim Bob was over on a workover or did an exploration season of vertical holes, ERD engineers were drilling world class ERD wells. It’s all we do!
Just as an instance, we had a client that had a particularly bad rep in their region of drilling. Time after time they refused help from reputable engineering companies. Their repeated failure eventually led them to sell out for pennies on the dollar. What did the purchaser do? They hired qualified and experienced engineers to come in and evaluate drilling practices, procedures, equipment, feasibility, personnel, etc.
As is with any project, the first well was a process of taking note and feeling out the project. By the second well, they had beaten the drilling curve for the first time in 8 years. The next well AFE was beaten by over 3 weeks. It doesn’t take a mathematician to know that at a large scale project spread rate of $300-400k per day, saving 3 week is a lot of money! This was not a one off situation. The wells were consecutively brought in under planned schedule/AFE for the subsequent wells until the end of the project.
You may ask, what is the secret? Was there a magic wand? The answer is an astounding NO. If you walk through the door barking orders at drillers and company hands, you will soon be packing your gear to head back to the house. You take an entire well to review if no valuable data is provided. You make subtle changes to the driller’s everyday routine on the first well that shave a few days. You look at any bottle necks that the project has. Are the shakers adequate? Is the fluid set what is most efficient for the goal? Are the AV’s being produced that are necessary for hole cleaning? Is the pipe selection the most suited for torque, AV, and SPP? Is the well design overall the most efficient that it can be? Can you save on pipe by running a liner? If you run a liner can you attain the velocity that is needed or would a circ sub be necessary? These are but a few of the questions that any logical outfit should ask of their program.
Let’s break it down from a practical stand point. Most drilling supervisors have a loose knowledge of drilling fluids. Most of the drilling world view plastic viscosity, yield point, weight, and funnel viscosity as true indicators of the health of their fluid system. In actuality, these are far from the correct properties to be looking at and could be the properties that are adding to your mud bill. If you base hole cleaning on yield point (often utilized for cleaning capacity) you are probably shooting higher than necessary thus costing in chemical additions. Are you looking at you HTHP fluid loss or API fluid loss for stability reasons? Are you looking at WPS or chlorides for inhibition purposes? Are you looking at MBT (clay content) to mitigate ECD via heightened and progressive gel strengths? Do you recognize the link between high end rheologies and SPP and the driving force of low end rheology versus ECD? Are you looking closely at low gravity solids content and it’s link to progressive gels and pump wear? You should be!
From a directional stand point, are you using a motor for cost savings when you could use a rotary steerable assembly? Some companies choose to go with a motor/agitator setup to save on daily cost. If you can drill it twice as fast with a rotary steerable, why wouldn’t you? What people often do not take into consideration is the orient time for slides, the slide ROP, the higher dog leg severity, and overall rig time that it takes to run the motor. If you run an agitator, are you getting what you paid for? Do you even know how to measure it? Some vendors do not even have an accurate process for measuring the force applied by an agitator. Most operators do not plan for or even have a clue as to what goes into planning a successful agitator run. Fluctuations in mud weight, rheology, and flow rate have a tremendous effect on the overall effectiveness of the agitator. The window of opportunity for agitator optimization is actually fairly small. Now, let’s say that you have an RSS assembly in the hole. Do you have the correct assembly? Is your BHA design conducive to achieving your overall goal? Are you drilling a tangent or are you building? Can you sacrifice a stabilizer to make a 2 bit run into a 1 bit run?
At the end of the day, the question of the day is this: Is it worth spending money while cutting overall cost? If a day rate for a competent engineer can save you 2,3 or even 4 weeks on a well at ANY spread rate, it makes sense that you take that chance if even for a 2-3 well trial. My advice, find a reputable service or an engineer that has proven success and save those millions of dollars that could potentially extend your project by a well or two.