Workover Cost and Payback Math for Permian Wells

Featured image for Workover Cost and Payback Math for Permian Wells

Knowing a workover cost is only half the decision. Workover economics is the comparison between what a workover costs and the extra net revenue it brings back to the owners who pay for it. A workover pays for itself when the incremental barrels, priced at what you actually realize at the lease and reduced by royalty, severance tax and the added operating cost, add up to the job cost within a payback window your partners accept.

How to run the numbers in six steps:

  1. Total the job cost line by line from the field ticket and vendor invoices (rig time, rods, pump, tubing, chemicals, trucking, rentals, supervision).
  2. Set the baseline rate: what the well makes if you do nothing (often a failing rate or zero), not what it made last year.
  3. Estimate the incremental rate: expected post-job rate minus the baseline, in barrels per day.
  4. Convert to net dollars per barrel: realized price x NRI x (1 - severance tax rate) - added variable LOE per barrel x WI.
  5. Divide cost by monthly net cash for a simple payback in months, then re-run with a monthly decline.
  6. Split the result by working interest so each partner sees their share of the cost, the revenue and the payout month on their statement.

The rest of this guide works through each step with real arithmetic, explains where the inputs come from, and ends with a checklist and FAQ.

What is a workover in oil and gas?

A workover is any job that brings a rig back to an existing well to repair it or restore production. In day-to-day Permian operations that covers rod parts, pump changes, tubing leaks, paraffin or scale cleanouts, acid jobs, and sometimes a recompletion into a new zone.

What is a workover rig?

A workover rig, often called a pulling unit or well servicing rig on rod-pumped wells, is a smaller mobile rig that pulls and runs rods and tubing in a well that is already drilled and completed. A drilling rig makes new hole; a workover rig services the hole you already have. Rig time is usually the largest single line on a rod or pump job, which is why it leads the cost table below.

Restoration or new capacity?

For the economics, the label matters less than two questions:

  • Is it restoring the well to the rate it had before it failed? This is the common rod, pump and tubing job. The baseline is the failed or failing rate.
  • Is it adding new capacity, for example a new zone? That is closer to a recompletion. In Texas a recompletion into a different reservoir generally needs a Form W-1 application to drill, recomplete or re-enter and a Form W-2 completion or recompletion report with the Railroad Commission of Texas (RRC), and the economics look more like a new well.

How a workover is booked (operating expense or capital) is a separate decision with accounting and tax consequences. We cover that line in LOE categories and the workover vs. recompletion test. This post assumes you have already classified the job and now need to know whether it paid, or will pay.

Step 1: Total the workover cost line by line

The single biggest error in workover economics is an incomplete cost. Invoices for one job often arrive from four to eight vendors over several weeks, and the trucking or rental invoice that shows up last is the one that gets coded to the wrong well or to general LOE.

Capture every line against the well and the job:

Cost line What to capture
Pulling unit or rig Days or hours, rate, crew
Rods and couplings Count, grade, size, new or inspected
Downhole pump Type, size, new or rebuilt
Tubing Joints replaced, footage
Chemicals and hot oil Volume, purpose (paraffin, scale, corrosion)
Trucking and water hauling Loads, hours
Rentals Equipment, days
Supervision and consulting Hours or day rate

A good rule: the job is not "closed" for economics until the field ticket, every vendor invoice, and the materials list all reference the same well and the same job. If you use paper tickets today, our oilfield maintenance log template shows the fields to require at the wellsite, and well master data shows how to keep one well ID across tickets and invoices.

Step 2: Set the right baseline rate

Payback is measured against what would happen without the job, not against the well's best month.

  • Pump or rod failure, well down: baseline is 0 BOPD.
  • Tubing leak or worn pump, well still making some oil: baseline is the current failing rate.
  • Gradual decline, job is a stimulation: baseline is the rate the existing decline would deliver over the same months.

Per-well rates come from your own well tests, gauging or production software. Keep using those tools for volumes. Public data helps you sanity check them: the RRC Production Data Query (PDQ) shows monthly reported production by lease. On a multi-well oil lease, PDQ will not isolate one well's response, so treat it as a lease-level check, not a well test.

Step 3: Estimate the incremental rate

Incremental rate = expected post-job rate - baseline rate.

For a restoration job, the expected post-job rate is usually the well's rate before the failure, checked against the last stable test. Be conservative. If the well had been slowly losing rate for months before it failed, use the recent stable rate, not the rate from a year ago.

Step 4: Convert barrels into net dollars per barrel

The owners who pay for a workover do not receive the gross price. For a working interest owner, each incremental barrel is worth:

Net per barrel (WI basis) = Realized price x NRI x (1 - severance rate) - Variable LOE per barrel x WI

Where each input comes from:

  • Realized price: your purchaser statement's net price at the lease, after the Midland differential and deductions. Benchmarks such as the EIA WTI Cushing spot price series and the EIA Short-Term Energy Outlook are useful for scenarios, but your own statements are the right input. See Midland Cushing differential for how to get from benchmark to wellhead.
  • NRI: the net revenue interest from the division order. For the math, see how to calculate NRI and working interest vs. NRI.
  • Severance rate: Texas taxes crude oil production at 4.6 percent of market value, and the Comptroller also lists an Oil Field Clean-Up Fee of 5/8 of a cent per barrel. Some wells qualify for reduced rates or exemptions; check the RRC's Texas severance tax incentives page. Gas is taxed at 7.5 percent of market value if the job also restores gas sales.
  • Variable LOE per barrel: the operating cost that rises with the restored volume, mostly electricity, chemicals and saltwater disposal for the extra fluid. Fixed costs such as pumper labor and insurance are paid whether or not the job happens, so leave them out of the incremental math.

Worked example: a rod and pump workover on a Permian lease

The numbers below are illustrative assumptions chosen to make the arithmetic easy to follow. They are not market rates or survey data. Replace each one with your own tickets, statements and division order decimals.

The situation. A pumping oil well on a West Texas lease made a stable 11 BOPD. A tubing leak and a worn pump drop it to 4 BOPD. The operator proposes a rod, pump and tubing job.

Ownership. The operator group holds 100% WI. The lease NRI to the working interest is 0.75. One partner, Partner B, owns 25% of the WI, so Partner B's NRI is 0.25 x 0.75 = 0.1875.

The cost, line by line

Line Amount
Pulling unit, 3 days at $4,200 per day $12,600
Rods and couplings $9,800
Downhole pump $6,400
Tubing, replacement joints $3,900
Hot oil and chemical $1,850
Trucking and water hauling $2,250
Supervision $1,700
Rentals $1,500
Total workover cost (8/8ths) $40,000

The incremental volume

  • Baseline (failing) rate: 4 BOPD
  • Expected post-job rate: 11 BOPD
  • Incremental rate: 11 - 4 = 7 BOPD
  • Monthly incremental volume (30-day month): 7 x 30 = 210 bbl

Net dollars per month at 100% WI

Assumptions: realized price $62.00 per barrel, Texas oil severance 4.6%, added variable LOE $4.00 per barrel.

  1. Gross incremental revenue (8/8ths): 210 x $62.00 = $13,020.00
  2. Revenue to the working interest at 0.75 NRI: $13,020.00 x 0.75 = $9,765.00
  3. Severance tax on that share: $9,765.00 x 0.046 = $449.19
  4. Revenue after severance: $9,765.00 - $449.19 = $9,315.81
  5. Added variable LOE (borne 100% by WI): 210 x $4.00 = $840.00
  6. Net incremental cash per month: $9,315.81 - $840.00 = $8,475.81

Simple payback: $40,000 / $8,475.81 = 4.72 months.

The clean-up fee at 5/8 of a cent per barrel adds about $1.31 per month on 210 barrels, so it does not change the answer here. It is left out for readability.

Payback with decline

Restored rates rarely stay flat. Assume the incremental volume declines 3% per month. Month n net cash is $8,475.81 x 0.97^(n-1).

Month Incremental bbl Net cash Cumulative net Cumulative minus cost
1 210.0 $8,475.81 $8,475.81 -$31,524.19
2 203.7 $8,221.54 $16,697.35 -$23,302.65
3 197.6 $7,974.89 $24,672.24 -$15,327.76
4 191.7 $7,735.64 $32,407.88 -$7,592.12
5 185.9 $7,503.57 $39,911.45 -$88.55
6 180.3 $7,278.47 $47,189.92 +$7,189.92

With decline, the job pays out in month 6 instead of during month 5. After 12 months at the same decline, cumulative net is about $86,498, so the job returns roughly 2.2 times its cost in the first year under these assumptions.

Break-even incremental rate

Turn the formula around to ask the question that matters before you call the rig: how many extra barrels per day does this job need to make to pay out in N months?

Required incremental BOPD = Cost / (N x 30 x Net per barrel)

Net per barrel here = $62.00 x 0.75 x (1 - 0.046) - $4.00 = $44.361 - $4.00 = $40.361

Target payback Required incremental rate (flat, no decline)
6 months $40,000 / (6 x 30 x $40.361) = 5.51 BOPD
12 months $40,000 / (12 x 30 x $40.361) = 2.75 BOPD
24 months $40,000 / (24 x 30 x $40.361) = 1.38 BOPD

If the best realistic outcome is 2 BOPD of incremental oil, this $40,000 job does not pay out within a year at $62 oil. That is a decision you can make before the pulling unit arrives.

What Partner B sees

Partner B pays 25% of the cost: $40,000 x 0.25 = $10,000. Partner B also gets 25% of the net incremental cash: $8,475.81 x 0.25 = $2,118.95 in month 1. Payback in months is the same for every WI owner, because cost and revenue split in the same proportion when NRI is a fixed fraction of WI. It differs only if a partner's NRI or cost share is not proportional, for example a carried interest or a non-consent penalty under the JOA.

The cash Partner B receives that month is a different question. Suppose the operator nets the workover against Partner B's distribution in the month it is charged, and the restored well's total monthly LOE is $5,200 (8/8ths):

  1. Whole-well gross revenue at 11 BOPD: 11 x 30 x $62.00 = $20,460.00
  2. At 0.75 NRI: $20,460.00 x 0.75 = $15,345.00
  3. Less 4.6% severance: $15,345.00 - $705.87 = $14,639.13
  4. Partner B's 25% share: $3,659.78
  5. Less Partner B's 25% of LOE ($1,300.00): $2,359.78
  6. Less Partner B's 25% of the workover ($10,000.00): -$7,640.22

Partner B gets no check that month and carries a negative balance of $7,640.22 forward.

Do you need an AFE for a workover?

An AFE (authority for expenditure) is the cost estimate the operator sends partners for approval before a job. Many joint operating agreements require one above a dollar threshold, and partners who must approve can elect in or out under the JOA's terms. A routine rod job may fall under the threshold; a recompletion usually does not. Put the break-even incremental rate from the table above on the AFE so partners see the payback case, not just the cost. This is exactly when the investor calls. Whether a workover is netted against distributions, billed separately, or approved first under an AFE depends on the joint operating agreement and the accounting procedure attached to it, commonly a COPAS accounting procedure. Check the JOA before you choose. For how to lay out the statement so the investor can follow the arithmetic, see audit ready investor distribution statements.

How to track workover economics after the job

The pre-job estimate is a forecast. The post-job review is what makes the next decision better.

Record the job against the well, not the lease

Code every cost line to the well and to the specific job. Lease-level coding hides which well consumed the money and makes the next workover decision on that lease guesswork.

Compare actual cost to the estimate within 30 days

Most overruns come from scope change in the hole: a "pump change" that turns into a fishing job, or extra tubing joints found bad. Note the reason on the record while the crew still remembers.

Check the actual incremental rate at 30, 60 and 90 days

Use your well tests or production system. If the 30-day rate is below the break-even rate from Step 4, flag the well before the next failure, not after.

Watch failure frequency

A well that needs a $40,000 rod job every six months is a different asset from one that needs it every three years. Track days between failures per well alongside the cost.

Show the arithmetic on the partner statement

Put the workover on its own line on the lease operating statement, with the job date and a short description, so partners can tie the charge to the work.

Where WellsManager fits

WellsManager is built for the record-keeping side of this workflow. Vendors and pumpers log inspections, repairs and workovers from a phone in Field Log, with photos and parts, so the work ticket exists before the invoice arrives. Well costs are entered line by line with the vendor, the maintenance record and the material lines attached, so when a partner asks what a workover cost, the answer is one well page. At period close you pull the lease operating statement and send investor distributions with the arithmetic shown.

WellsManager is not a production gauging or SCADA tool. Keep your existing production software for well tests and volumes, and use those rates as the inputs to the payback math above. See what each WellsManager module does or get a price for your operation.

Workover economics checklist

Before the job:

  • Well ID and API number match on the ticket, AFE (if used) and every invoice
  • Baseline rate defined (failing rate or zero), with source and date
  • Expected post-job rate based on the last stable test, not the best month
  • Realized price taken from recent purchaser statements, not a benchmark
  • NRI and WI decimals checked against the division order and JOA
  • Severance rate confirmed, including any exemption or reduced rate
  • Variable LOE per barrel estimated (power, chemical, SWD)
  • Break-even incremental rate calculated for your target payback
  • Classification decided (restoration workover vs. recompletion) and any RRC filing identified
  • JOA checked for AFE thresholds and how partner charges are billed or netted

After the job:

  • Every vendor invoice coded to the well and the job
  • Actual cost compared to estimate, with reasons for any overrun
  • Incremental rate checked at 30, 60 and 90 days
  • Payout month recorded
  • Days since last failure updated
  • Workover shown as its own line on the LOS and partner statements

Frequently asked questions

What is a good payback period for a workover?

There is no single standard. It depends on oil price, the well's remaining life and your partners' expectations. The useful approach is to set a target payback in months, compute the break-even incremental rate for that target, and compare it to a realistic post-job rate.

How much does a workover cost?

There is no single number. Cost depends on rig days, what gets replaced (rods, pump, tubing), chemicals, trucking and rentals. The worked example above totals an illustrative $40,000 rod, pump and tubing job line by line. Use your own field tickets and vendor invoices, and total every line against the well before you judge payback.

Should the baseline be zero if the well is still producing?

No. If the well is still making oil, the baseline is the current failing rate. Using zero overstates the incremental volume and makes the job look better than it is.

Does severance tax apply to the incremental barrels?

Yes. Texas crude oil production tax is 4.6% of market value under the Comptroller's rules, unless the well qualifies for a reduced rate or exemption. Apply it to the incremental revenue, at each owner's NRI share.

Is a workover an operating expense or a capital cost?

It depends on what the job does and on your accounting and tax policies. A job that restores prior production is often treated differently from one that adds new capacity. Federal tax rules on repairs vs. improvements and on intangible drilling costs can apply, so confirm the treatment with your CPA. Our LOE categories guide covers the operating side.

Can I use RRC production data to measure a workover's response?

Only as a lease-level check. The RRC Production Data Query reports oil production by lease and month. On a multi-well lease you still need per-well tests to see one well's response.

What does AFE mean for a workover?

AFE stands for authority for expenditure: the operator's cost estimate for a planned job, sent to working interest partners for approval when the JOA requires it. Compare the final workover cost to the AFE within 30 days of the job.

How do partners pay for a workover?

That is set by the JOA and its accounting procedure. Common options are billing partners directly, netting the cost against their distributions, or requiring AFE approval above a dollar threshold. Make the method clear on the statement so the partner can follow the math.

Sources