Mathcad Drilling Cost Per Foot Analysis Worksheet-1 [PDF]

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Wellbore Drilling Optimization

Peter Aird rev 1.1, March 2004 Prime 7.0 rev August 2021

Drilling cost per ft analysis. Whether operating in low or high wellbore drilling operating, cost environments. Monitoring, measuring, managing and being in control of bit run costs per ft, on a well's section basis, is till important to be conducted to assure desired wellbore drilling optimization value and outcomes result. Drilling Cost per foot analysis exists as a useful economic 'good or bad' wellbore drilling optimization tool to assess value added or not. It is used to: 1. Compare wellbore drilling optimization on a drilled 'bit run' interval basis. 2. Assess bit, drilling, tripping and operations activities to improve wellbore drilling optimization and bit selection, 3. It DOES NOT and is not is intended to offer a Historical Record of Costs.

Purpose of is this method is to be used/applied as a measured approach to predict future planned well's, not to analyze the past Objective Factors to consider as illustrated in this worksheet in regards to selecting the correct bits to be run, is to improve overall wellbore drilling optimization through the elimination of loss that in turn delivers cost reduction. e.g. Bit cost, rig cost, tripping, circulating, associated operations, Bottom hole assembly handling, tripping and wellbore evaluation times. 4167 $ Cr ≔ ――― $≔¤ Cb ≔ 15000 $ hr

Data Input.

Cb = bit cost (currency) Cr = Total rig rate & services cost (Currency per hour)

⎡ Di ⎤ ⎡ 2700 ⎤ ⎢⎣ Do ⎥⎦ ≔ ⎢⎣ 9300 ⎥⎦ ⋅ ft

Di = Depth in

⎡ 1000 ⎤ ft Tr ≔ ⎢ 1500 ⎥ ⋅ ― ⎢ ⎥ hr ⎣ 2500 ⎦

Do = Depth out

Tr = Average tripping rates BHA = Total Bha handling time Dt = On bottom (ACTUAL) drilling time Ct = Circulating, reaming, connection time We = Wellbore Survey MWD and LWD logging evaluation time (St)

Worked Example. Step # 1; Calculate the round trip time (Rt) for tripping and BHA handling time as input above.

Step # 2; Calculates total bit run cost per foot (CPF) based on all operating data input and step #1 calculations.

Step # 3; Calculates the Bit cost per foot (BCPF) based on bit cost, rig cost, tripping & drilling time only.

BHA ≔ 6 ⋅ hr

⎡ Dt ⎤ ⎡ 36 ⎤ ⎢ Ct ⎥ ≔ ⎢ 12 ⎥ ⋅ hr ⎢ ⎥ ⎢ ⎥ ⎣ We ⎦ ⎣ 4 ⎦ ⎡ 18 ⎤ ⎛ Di + Do ⎞ ⎢ 14 ⎥ hr Rt ≔ ⎜――― = + BHA ⎟ ⎢ ⎥ ⎝ Tr ⎠ ⎣ 10.8 ⎦ ⎡ 46.468 ⎤ Cb + Cr ⋅ (Rt + Ct + We + Dt) ⎢ $ CPF ≔ ――――――――― = 43.943 ⎥ ― ⎢ ⎥ Do - Di ⎣ 41.922 ⎦ ft ⎡ 36.366 ⎤ Cb + Cr ⋅ (Rt + Dt) ⎢ $ BCPF ≔ ―――――― = 33.841 ⎥ ― ⎢ ⎥ Do - Di ⎣ 31.821 ⎦ ft

Example Exercises. Exercise 1; Recalculate for a $65,000 PDC bit, What impact does a far more expensive bit offer, (note: that may offer can far greater average ROP) in terms of cost/ft, if drilling time was reduced by: 6, 12 and 18hrs? Assume all other factors remain the same. Exercise 2; if well was an Offshore, Deepwater well, in 5000ft water depth i.e. 10,000ft more pipe to trip on each bit run), with a Total rig and services cost @ ($720,000pd $30,000/hr). Re run the cost per ft numbers, What now drives drilling cost/ft metrics more than anything else in your summation.? Exercise 3: Using the original data, due to deteriorating wellbore conditions and drilling issues, significantly more time was required to make connections (i.e. +30mins every stand). At TD well had to be ream out at 5stands per hr to the casing shoe at 6,000ft, with 8hrs more circulating required. Prior to normal cased-hole tripping resumed. How much has deteriorated wellbore conditions affected cost per ft. Conclude the impact of this?

Wellbore Optimization: Rev. Mathcad Prime Drilling 7.0 Aug 2021

Cost Per Foot Limiters? www.kingdomdrilling.co.uk

The cost per foot approach method is simple, yet has several inherent limitations to be recognized,

Wellbore Drilling Optimization: Cost Per Foot Limiters? The cost per foot approach method is simple, yet has several inherent limitations to be recognized, analysed and addressed. For users to assure wellbore drilling optimization and improvement results from evidence data use and outputs that result. The equations may be simple, and inputs appear straightforward, but can be misleading. because, Ÿ There is wide scope for error and uncertainty with the input data. (see notes that follow) Ÿ Secondly, everything is based on historical and/or predictive, not actual data. e.g. one cannot predict with certainty how bits or wellbore operations (good or bad) result on each planned bit run.

Uncertainties in Inputs User must continually examine all inputs to the equation and identify uncertainties that apply. To assure evident accuracy and precision as one can.

Bit Costs Bit cost seems simple and absolute, but how to cater for re-run bits? What to apply to the total cost of the first run and zero cost to subsequent runs, or should we spread the cost evenly between each bit run, or employ some other normalised method? Repaired bits introduce a similar complexity. Repair costs for PDC bits can be substantial, up to 40% of the original price. How should costs be distributed? What about multiple repairs? There is no simple or correct answer these questions. Good arguments to be made and assessed with two important aspects to account for i.e. 1. Be consistent in assumptions made 2. Clearly state how assumptions were derived. Never use a cost per foot figure that is not accompanied by a full statement of values and explanation how data was obtained, determined and evaluated.

Rig Costs Rig operating cost per hours can also be as ‘variable’ and inconsistent as bit cost. Variable rig rates with time? What if rates were far too low compared to todays rates. How do we normalise rig rates, times via some nominal multiplier, e.g. two or three? Do we take the total anticipated well cost and divide it by well duration? Alternatively, should we only use the direct drilling costs? Note: There is not a correct answer, what is needed is a succinct, precise and consistent approach and clearly state and record all assumptions.

Rig 'Trip' Time Trip time is the next element in the equation. Using previous trip times from the well may not work that well– remember main interest is in projected wellbore drilling optimization, not historic. Trip times may also vary greatly with each rig, even rig crews capabilities: What is merited are figures that accurately reflect the rig time for handling, tripping, operating on the planned wellbore section with the intended rig. Often a calculated operating time is used: e.g. one thousand feet per hour round trip from the Depth is common. Sometimes an over-head time of one two or several hours may be for BHA changes and other standard operating activities. e.g. If a wiper trip is an integral part of the operation and is, therefore, planned, it should be included. Wiper trips that have occurred historically for incidental hole problems should be ignored. In all of the above rig aspects, EVIDENT rig wellbore operating data must be obtained and evaluated to assure precision warranted.

Drilling Time Again can be suspect and open to wide interpretation. e.g. offset, analogue, R.O.P. well data, showed a 12% difference in ROP, was this on bottom ROP or well all operations such as connections, surveys etc included or excluded. There is no right or wrong figure: What must be assured is that data used is evident and consistent in its entry to assure and recognize choices made will alter the values and outcomes required. e.g. Where wellbore drilling optimization assessments are close, a small adjustment in trip time calculation can alter the preferred bit selection and choice.

Rev. Mathcad Prime 7.0 Aug 2021

www.kingdomdrilling.co.uk