Lesson 12 Candidate and Technique selection

Lesson 12 Candidate - PETE 689 Underbalanced Drilling(UBD Lesson 12 Lesson 12 Selecting an Appropriate Technique Read UDM Chapter 4 pages 4.1­4.54

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Unformatted text preview: PETE 689 Underbalanced Drilling (UBD) Lesson 12 Lesson 12 Selecting an Appropriate Technique Read: UDM Chapter 4 pages 4.1­4.54 Harold Vance Department of Petroleum Engineering Selecting an Appropriate Selecting an Appropriate Technique • Potential applications and candidate technique. • Technical feasibility. • Economic analysis. Harold Vance Department of Petroleum Engineering Required Data For UBO Required Data For UBO Candidate Identification Pore pressure/gradient plots. Actual reservoir pore pressure. ROP records. Production rate or reservoir characteristics to calculate/estimate production rate. • Core analysis. • • • • Harold Vance Department of Petroleum Engineering Required Data For UBO Candidate Identification • • • • • Formation fluid types. Formation integrity test data. Water/chemical sensitivity. Lost circulation information. Fracture pressure/gradient plot. Harold Vance Department of Petroleum Engineering Required Data For UBO Candidate Identification • Sour/Corrosive gas data. topography/actual • Location location. • Well logs from area wells. • Triaxial stress test data on any formation samples. Harold Vance Department of Petroleum Engineering Poor Candidates For UBD Poor Candidates For UBD • High permeability coupled with high pore pressure. • Unknown reservoir pressure. • Discontinuous UBO likely (numerous trips, connections, surveys). • High production rates possible at low drawdown. Harold Vance Department of Petroleum Engineering Poor Candidates For UBD • Weak rock formations prone to wellbore collapse at high drawdown. • Steeply dipping/fractured formation in tectonically active areas. • Thick, unstable coal beds. Harold Vance Department of Petroleum Engineering Poor Candidates For UBD Young, geo­pressure shale. H2S bearing formations. Multiple reservoirs open with different pressures. • Isolated locations with poor supplies. • Formation with a high likelihood of corrosion. • • • Harold Vance Department of Petroleum Engineering Good Candidates For UBD Good Candidates For UBD • Pressure depleted formations. • Areas prone to differential pressure sticking. • Hard rock (dense, low permeability, low porosity). • “Crooked­hole” country and steeply dipping formations. Harold Vance Department of Petroleum Engineering Poor Candidates For UBD Lost­returns zones. Re­entries and workovers (especially pressure depleted zones). • Zones prone to formation damage. • Areas with limited availability of water. • • Harold Vance Department of Petroleum Engineering Good Candidates For UBD Good Candidates For UBD • • • • Fractured formations. Vugular formations. High permeability formations. Highly variable formations. Harold Vance Department of Petroleum Engineering Good Candidates For UBD • Once the optimum candidate has been identified, the appropriate technique must be selected, based on much of the same data required to pick the candidate. Harold Vance Department of Petroleum Engineering Candidate Decision Tree­Sheet 1 Candidate Decision Tree­Sheet 1 Previous history of underbalanced Operations (UBO)? No Hydrocarbons anticipated Yes Go to Sheet 2 No Drilling problems anticipated No No UBO Yes Lost circulation Yes No Yes Stuck pipe Cost/safety benefits No No UBO No Hard drilling (ROP/bit) Yes No No UBO Detailed engineering (cost, safety, reservoir, Mechanical main drivers) Harold Vance Department of Petroleum Engineering Yes Candidate Candidate Decision Tree­Sheet 2 Candidate Decision Tree­Sheet 2 Yes Depleted reservoir Go to Sheet 3 No No Drilling Problems anticipated No UBO Yes Yes Lost circulation Reservoir damage Production impairment No UBO Yes No Yes Stuck pipe Cost /safety benefits No Hard Drilling (ROP/bit) No No Yes Yes No No UBO Harold Vance Department of Petroleum Engineering No UBO Candidate Candidate Decision Tree­Sheet 3 Yes Drilling problems anticipated No No UBO No Lost circulation Yes No Reservoir damage Production impairment Yes Stuck pipe Yes No Candidate Hard Drilling (ROP/bit) Cost /safety benefits No Yes No UBO No No UBO This decision tree can be found on the IADC website (www.iadc.org). This decision tree can be found on the IADC website (www.iadc.org). Click on Committees. Click on Underbalanced Drilling committee. Click on decision tree. Harold Vance Department of Petroleum Engineering Yes Candidate Potential Applications and Potential Applications and Candidate Technique Harold Vance Department of Petroleum Engineering Low ROP Through Hard Rock Low ROP Through Hard Rock Dry air. Mist, if there is a slight water inflow. Foam, if there is heavy water inflow, if the borehole wall is prone to erosion, or if there is a large hole diameter. • N2 or natural gas, if the well is producing wet gas and it is a high angle or horizontal hole. • • • Harold Vance Department of Petroleum Engineering Lost Circulation Through The Lost Circulation Through The Overburden • Aerated mud, if the ROP is high (rock strength low or moderate) of if water­ sensitive shales are present. • Foam is possible if wellbore instability is not a problem. Harold Vance Department of Petroleum Engineering Differential Sticking Through Differential Sticking Through The Overburden • Nitrified mud, if gas production is likely, especially if a closed system is to be used. • Aerated mud, if gas production is unlikely and an open surface system is to be used. • Foam is possible if the pore pressure is very low and if the formations are very hard. Harold Vance Department of Petroleum Engineering Formation Damage Through A Formation Damage Through A Soft/Medium­Depleted Reservoir • Nitrified brine or crude. string injection, if the pore pressure is very low. ► parasite injection, if the pore pressure is high enough and a deviated/horizontal hole needs conventional MWD and/or mud motor. ► Temporary casing injection, if the pore pressure is intermediate and a high gas rate in needed. ► Harold Vance Department of Petroleum Engineering Formation Damage Through A Soft/Medium­Depleted Reservoir • Nitrified brine or crude, con’t. ► String and temporary casing injection, if the pore pressure is very low and/or if very high gas rates. • Foam, if the pore pressure is very low and an open surface system is acceptable. Harold Vance Department of Petroleum Engineering Formation Damage Through A Formation Damage Through A Normally Pressured Reservoir • Flowdrill (use a closed surface system if sour gas is possible). Harold Vance Department of Petroleum Engineering Lost Circulation/Formation Damage Lost Circulation/Formation Damage Through A Normally Pressured, Fractured Reservoir • Flowdrill (use an atmospheric system if no sour gas is possible). Harold Vance Department of Petroleum Engineering Formation Damage Through Formation Damage Through An Overpressured Reservoir. • Snub drill (use a closed surface system is sour gas is possible). Harold Vance Department of Petroleum Engineering Technical Feasibility Technical Feasibility • In evaluating the feasibility of candidate drilling techniques, a controlling factor is the range of anticipated borehole pressures which will be required for each zone to be drilled. • The upper limit for UB conditions is formation pore pressure. • Lower limit will generally be regulated by the lowest pressure at which wellbore stability is ensured. Harold Vance Department of Petroleum Engineering Technical Feasibility • First step is to determine the anticipated pressures. • Step two is to determine which methods are functional within the anticipated pressure window. Harold Vance Department of Petroleum Engineering Technical Feasibility • Other considerations are: Will there be sloughing shales? ► Are aqueous fluids inappropriate? ► Will water producing horizons be penetrated? ► Will multiple, permeable zones, with dramatically different pore pressures, be encountered? ► Harold Vance Department of Petroleum Engineering Technical Feasibility • Other considerations con’t: What is the potential for chemical formation damage, due to fluid/fluid or fluid/formation interaction and is this an overwhelming problem, regardless of what wellbore pressure is used? ► Is there a potential for sour gas production? ► Harold Vance Department of Petroleum Engineering Technical Feasibility • Other considerations con’t: Are there features of the well geometry which dictate specific underbalanced protocols? ► What is the local availability of suitable equipment and consumables (including liquids and gases for the drilling fluids)? ► Harold Vance Department of Petroleum Engineering Borehole Pressure Limits Borehole Pressure Limits • Pore pressure The wellbore pressure must be maintained below the formation pressure in all open hole sections. ► If there is no formation fluid inflow, borehole pressures with dry gas, mist, foam or pure liquid will be lower when not circulating. ► With fluid influx, borehole pressure can increase or decrease when not circulating. ► Harold Vance Department of Petroleum Engineering Borehole Pressure Limits • Pore pressure Best practice is to use the: Lower bounds for pore pressure prediction when choosing a technique. ► While surface equipment capacity and drilling specifics should be based on an upper bound. ► Harold Vance Department of Petroleum Engineering Borehole Pressure Limits • Wellbore stability provides the lower limit to the allowable borehole pressures. • Will be discussed later. Harold Vance Department of Petroleum Engineering Borehole Pressure Limits • Hydrocarbon production rates can sometimes set the lower bound, depending upon the surface equipment available. • Formation damage may effect the tolerable drawdown due to fines mobilization in the producing formation. Harold Vance Department of Petroleum Engineering Borehole Pressure Limits • Backpressure from a choke can sometimes be used to protect the surface equipment from excess production rates or pressures. • This also increases the BHP. • The allowable backpressure is limited by the pressure rating of the equipment and formation upstream of the choke. Harold Vance Department of Petroleum Engineering Borehole Pressure Limits • When using compressible fluids, it is usually more cost effective to switch to a higher density fluid than to choke back the well. Harold Vance Department of Petroleum Engineering Borehole Pressure Limits • Applying back pressure will: Increase the gas injection pressure. ► Increase the gas injection rate required for acceptable hole cleaning. ► These both will increase the cost of the gas supply. ► Harold Vance Department of Petroleum Engineering Borehole Pressure Limits • With a gasified liquid, BHP can usually be increased by reducing the gas injection rate. • When drilling with foam, back pressure may be necessary to maintain foam quality. • Holding back pressure is most beneficial when drilling with liquids. Harold Vance Department of Petroleum Engineering Borehole Pressure Limits • Once the maximum tolerable surface pressure is reached, production rate can only be further reduced by increasing downhole pressure by increasing the effective density of the drilling fluid. Harold Vance Department of Petroleum Engineering Implications of Drilling Implications of Drilling Technique Selection • • • • Pore pressure gradients vary with depth. Formation strength varies with depth. In­situ stresses vary with depth. The tolerable stresses, are affected by by the inclination and orientation of deviated, extended reach and horizontal wells. Harold Vance Department of Petroleum Engineering Implications of Drilling Technique Selection • Production rates depend on the length of the reservoir that is open to the wellbore and on the underbalanced pressure. Harold Vance Department of Petroleum Engineering Implications of Drilling Technique Selection • Once the borehole pressure limits, corresponding to wellbore instability and excessive production rate, have been determined , a first pass evaluation of the different drilling techniques can be performed. Harold Vance Department of Petroleum Engineering Example 1 Example 1 4500 • No wellbore stability problems. • Surface equipment can handle the anticipated AOF. • Minimal water inflow is expected. 3500 Borehole Pressure (psi) • Shallow, normally pressured reservoir. 4000 3000 2500 2000 1500 1000 500 0 0 2000 4000 6000 8000 10000 True Vertical Depth (feet) Stability regimes for the well described in Example 1. Harold Vance Department of Petroleum Engineering Example 2 • Lost circulation and differential sticking is a problem with mud. • No instability problems anticipated if borehole pressure is > 2 ppg. • Production rate is low. 4500 4000 3500 Borehole Pressure (psi) • Depleted sandstone from 3,000 to 4,000 ft with a pore pressure gradient of 5 ppg. Pore pressure above the sand is 8 ppg. 3000 2500 2000 1500 1000 500 0 0 2000 4000 6000 8000 10000 True Vertical Depth (feet) Stability regimes for the well described in Example 2. Harold Vance Department of Petroleum Engineering Example 3 • Pore pressure = 8 ppg 4500 • Shale from 6,000­8,000’ requires a minimum wellbore pressure of 7 ppg 4000 • Target zone is 9,000’ • Reservoir itself is competent unless borehole pressure < 5 ppg • Expect high flow rates. • maximum drawdown = 500 psi • Pore p. at 9,000’ = 3,744 psi Borehole Pressure (psi) 3500 3000 2500 2000 1500 1000 500 0 4000 5000 6000 7000 8000 9000 10000 True Vertical Depth (feet) • min BHP = 3,244 psi or 6.93 ppg Stability regimes for the wells described in Examples 3 through 5 Harold Vance Department of Petroleum Engineering Example 4 4500 4000 • Equivalent to 7.79 ppg. • Diesel or crude gives a pressure lower than this. Plain water is too dense. Borehole Pressure (psi) • Maximum drawdown = 100 psi. 3500 3000 2500 2000 1500 1000 500 0 4000 5000 6000 7000 8000 9000 10000 True Vertical Depth (feet) Stability regimes for the wells described in Examples 3 through 5 Harold Vance Department of Petroleum Engineering Example 5 4500 • This would not supply sufficient support for the shale above. 4000 3500 Borehole Pressure (psi) • Reservoir is depleted to 6.5 ppg. Maximum drawdown is 500 psi. The tolerable range for ECD through the reservoir would be 5.4­6.5 ppg. A gasified liquid would be required. 3000 2500 2000 1500 1000 500 0 4000 5000 6000 7000 8000 9000 10000 True Vertical Depth (feet) Stability regimes for the wells described in Examples 3 through 5 Harold Vance Department of Petroleum Engineering Evaluating Highly Productive Evaluating Highly Productive Formations detailed numerical • Require analyses of circulating pressures. • Formation fluid influx interacts with drilling fluids which effect borehole pressure ­ effecting influx rate. Harold Vance Department of Petroleum Engineering Evaluating Highly Productive Formations • When circulation stops, the influx lifts mud from wellbore. • This changes the borehole pressure and the production rate. Harold Vance Department of Petroleum Engineering Evaluating Highly Productive Formations • Choking back the well returns further complicates the calculation of borehole pressures and production rate. the fluid is incompressible, • If backpressure changes BHP by the amount of pressure applied. • If the fluid is compressible, backpressure changes density, velocity, and BHP. Harold Vance Department of Petroleum Engineering Evaluating Highly Productive Formations • Uncertainty of input parameters in simulators leads to uncertainty in output. • In many cases these uncertainties can make simulations in technique selection unjustified. Harold Vance Department of Petroleum Engineering Water Production Water Production • Production of small quantities of water makes dry gas drilling difficult. • If offset wells have a history of water production, dry gas drilling below the water zone is probably impractical. Harold Vance Department of Petroleum Engineering Water Production • When misting, higher gas rates are required to prevent slug flow. • Slug flow can damage the borehole and surface equipment. • Higher injection rates and the increased density in the annulus may require boosters on the compressors. Harold Vance Department of Petroleum Engineering Water Production • Large water influxes may require foams. • High disposal costs can sometimes make mist drilling impractical. • Higher density foams can decrease water influx, however the increased volume of make­up water may make disposal still impractical. Harold Vance Department of Petroleum Engineering Water Production • If high water influx makes gas and foams impractical, aerated mud or low density liquids may be required. Harold Vance Department of Petroleum Engineering Multiple Permeable Zones Multiple Permeable Zones • If all zones are to be drilled UB, the circulating pressure must satisfy the borehole pressure requirements for all open permeable zones, simultaneously. • Several factors can prevent this from happening. Harold Vance Department of Petroleum Engineering Factors Preventing UB Factors Preventing UB In All Zones • The ECD of compressible fluids increases with increasing depth. • In vertical wells, it is possible for a permeable zone close to the bit to be overbalanced when a permeable zone higher up hole, with the same pore pressure gradient, is UB. Harold Vance Department of Petroleum Engineering Factors Preventing UB In All Zones • This effect is more pronounced in high angle and horizontal wells. • AFP increases along the borehole even if formation pore pressure remains relatively constant along the borehole. Harold Vance Department of Petroleum Engineering Factors Preventing UB In All Zones • Changes in pore pressure gradient along the wellbore may be present. • This can be due to abnormally pressured formations, or partially depleted formations. Harold Vance Department of Petroleum Engineering Multiple Permeable Zones Multiple Permeable Zones • The major concern with multiple permeable zones is the potential for underground blowouts. • Extreme care must be taken to prevent this from happening when pressure changes occur such as tripping, or connections. Harold Vance Department of Petroleum Engineering If Cross Flows Cannot Be Tolerated: If Cross Flows Cannot Be Tolerated: • Use a different drilling technique that allows all permeable zones to remain UB, if possible. • Kill the well before suspending circulation. • Change the casing scheme so that the upper formations are cased of before penetrating the lower zone in the hole. Harold Vance Department of Petroleum Engineering Sour Gas Sour Gas • There must be no possibility of releasing hydrogen sulfide into the atmosphere while the well is being drilled or completed. • If any is produced during drilling it must be disposed of in a suitable flare. Harold Vance Department of Petroleum Engineering Sour Gas • H2S can become entrained in any liquid in the wellbore, and must be completely removed from the fluid and flared before any of the liquids are returned to any open surface pits. • The separation process should be completed in a closed vessel. Harold Vance Department of Petroleum Engineering Sour Gas • Sour gas can become entrained in foams. • The foam must be completely broken prior to separation. • Unless effective defoaming can be guaranteed foams cannot be used in closed systems, and should not be used in the presence of Hydrogen Sulfide. Harold Vance Department of Petroleum Engineering Drilling/Reservoir Fluid Drilling/Reservoir Fluid Incompatibility • It can be difficult to prevent temporary overbalance. • Drilling fluids should be tested for compatibility with formation fluids. Harold Vance Department of Petroleum Engineering Hole Geometry Hole Geometry • A compressible fluid will have a greater ECD in deep wells than in shallow wells. • Annular gas injection only reduces the density of the fluids above the injection point. Drillpipe gas injection may be necessary if long vertical sections are to be drilled with gasified liquid. Harold Vance Department of Petroleum Engineering Hole Geometry • Increasing ECD with depth may make it impossible to maintain the proper foam quality in deep wells. Backpressure may be required, increasing the gas supply needed. • Increasing hole size makes hole cleaning more difficult. Harold Vance Department of Petroleum Engineering Hole Geometry • Large hole sizes may require larger diameter surface equipment. Larger surface diverter equipment may not have the pressure rating of smaller resulting in lower back pressure capabilities. Harold Vance Department of Petroleum Engineering Naturally Fractured Formations Naturally Fractured Formations • In fractured formations, high viscosity drilling fluids, circulating at low rates may prevent hole enlargement and still maintain UB. • Stiff foams may be the preferred candidate. Harold Vance Department of Petroleum Engineering Logistics Logistics • Water supplies may be limited in some areas, and a technique that limits water use may be chosen. • Availability and access to the gaseous phase can influence the choice of gas used. Harold Vance Department of Petroleum Engineering Logistics • Offshore locations generally do not have the same space available as land locations. • Equipment used on surface locations may not be suitable for offshore locations. • Modular closed systems must be used offshore. Harold Vance Department of Petroleum Engineering Logistics • The high production rates necessary for offshore wells to be economically viable may make them unlikely candidates for UBD. Harold Vance Department of Petroleum Engineering Economic Analysis Economic Analysis • Rules of thumb. ► UBO increases costs 1.25 ­ 2.0 times the cost per day over conventional. ► but may be accomplished in 1/4 to 1/10 of the time. Harold Vance Department of Petroleum Engineering Economic Analysis • Rules of thumb. ► In permeable rock ROP may be increased from 30% to 300% as well goes from overbalanced to balanced. ► Below balance ROP will increase another 10­20%. ► In impermeable rock, ROP will increase 100­200%. Harold Vance Department of Petroleum Engineering Drilling Days 0 0 20 40 60 80 100 120 1000 2000 Depth (feet) 3000 4000 5000 6000 7000 8000 9000 10000 Gas and mud effect on drilling time (after Moore, 1974 56). Harold Vance Department of Petroleum Engineering Rotating Time (hours) 0 0 10 20 30 40 50 60 70 80 90 100 500 Depth (feet) 1000 1500 2000 2500 3000 Air and water effect on drilling time (after Moore, 1974 56). Harold Vance Department of Petroleum Engineering Steps for Economic Analysis Steps for Economic Analysis 1.Determine the expected penetration rate or drilling time of each candidate hole­interval, if the operation were to be carried out conventionally. 2.Estimate the daily cost of conventional drilling operations for each prospective hole­interval based on empirical data. Harold Vance Department of Petroleum Engineering Steps for Economic Analysis 3.Multiply the conventional daily 3. cost by an underbalanced factor (1.3­2.0, depending on difficulty of the operation) to get the expected daily cost of UBO. 4.Apply the expected underbalanced operating cost by the anticipated underbalanced drilling ROP to get the total cost for each interval. Harold Vance Department of Petroleum Engineering Factors that Effect the Factors that Effect the Economics of UBD • • • • Penetration rate. Bit selection. Bit weight and rotary speed. Mud weight. Harold Vance Department of Petroleum Engineering Completions and Stimulation Completions and Stimulation UBO does not save completion time. But, if you are going to drill UB to prevent formation damage, you better complete UB. • Mitigation of formation damage in wells that will need to be hydraulically fractured (except naturally fractured) may be a poor and unnecessary economic decision. • • Harold Vance Department of Petroleum Engineering Formation Evaluation Formation Evaluation • Real time formation evaluation possible. • UB coring possible. Harold Vance Department of Petroleum Engineering Environmental Savings Environmental Savings • Closed systems make smaller reserve pits and locations possible, but there is additional costs of rental of the systems. Harold Vance Department of Petroleum Engineering Fluid Type Fluid Type • The bottom line controlling factor may be the specific fluid system adopted. Each fluid type has technical and economic advantages and limitations. Harold Vance Department of Petroleum Engineering Drilling Method Drilling Method Possible problems if water flow and reduction in rig is encountered time. Low bit cost Air Problems and/or Potential Expenditures High penetration rates or Fluid System Savings Hole erosion, if poorly Low water requirement consolidated. Possibility of downhole fire, if hydrocarbons are encountered. No mud removal Supplementary equipment Low additives cost rental. Is not suitable for H2S Harold Vance Department of Petroleum Engineering Drilling Method Drilling Method or Fluid System Savings High penetration rates Problems and/or Potential Expenditures Problems if water flow is encountered. and reduction in rig time. Gas (Nitrogen or Natural Gas) Cost of gas and/or rentals. Low bit cost Hole erosion, if poorly consolidated. Low water requirement Cost is high if a market for the gas No mud removal exist. Rig safety. Low additives cost Supplementary equipment rental If H2S is expected, consider a closed system. Harold Vance Department of Petroleum Engineering Drilling Method Drilling Method or Fluid System Savings High penetration rates Problems and/or Potential Expenditures Problems if substantial water flow is and reduction in rig time. Low bit cost Mist encountered. Gas Cost if air not used. Hole erosion, if poorly consolidated. Low water requirement Shale stability. Disposal of waste water/gas and No mud removal supplementary rental cost. Air­mist not suitable if H2S is present. Modest additives cost. Equipment rental. Harold Vance Department of Petroleum Engineering Drilling Method Drilling Method Savings or Fluid System Problems and/or Potential Expenditures High penetration rates and reduction in rig time. Gas cost if air not used. Low bit cost. Careful metering required. Low water requirement. Specialized metering High solids carrying capacity. Stable foam Considerable foamer cost. equipment. Defoaming. Good hole cleaning capability. Compatible with oil, salt water, Considerable cost. calcium carbonate and most formation contaminants. Can safely entrain a considerable Separation and disposal. volume of gas into aqueous foam, rendering in non­flammable until sumped. Can handle large flows of water. Water disposal Harold Vance Department of Petroleum Engineering Drilling Method Drilling Method or Fluid System Savings High penetration rates and reduction in rig time. Low bit cost. Problems and/or Potential Expenditures Considerable mud and chemical cost. Gas cost if air is not used. Fluid degradation possible if oil, salt water or calcium chloride Stiff Foam Low water requirement. are encountered. Specialized metering equipment. High solids carrying Defoaming. capacity. Good hole cleaning capability. Harold Vance Department of Petroleum Engineering Drilling Method Drilling Method or Fluid System Savings Problems and/or Potential Expenditures Expense of running a parasite string or a temporary casing string. Higher bottomhole pressures. Higher gas rates are required. Slow pressure response if a parasite string is used. Low underbalance pressure may cause transient departures from Gasified Liquids underbalanced conditions and comparison to dry gases or advantages to impairment Tool problems with drilling reduction may be lost. injection. mist (refer to chapter 6). Reduced drillstring wear. Supplementary surface Reduced potential for equipment. Corrosion potential (and Improved directional drilling in downhole fires in vertical holes requirement for inhibitors 62) is air with aqueous fluids. is used. Harold Vance Department of Petroleum Engineering Drilling Method Drilling Method or Fluid System Savings Problems and/or Potential Expenditures instability. No gas supply system. Excessive production is possible. Safety issues associated with oil and MWD units can be and gas on drill site. used. Can be used in situations Supplementary equipment and where surface pressure is safety considerations. too high for flowdrilling. Can be used at pressures Snub Drilling or CT equipment and safety measures. Conventional mud motors Mudcap Drilling Supplementary surface reduce the possibility of Flowdrilling Higher borehole pressures Snubbing or CT unit. too high for conventional units and underbalanced drilling equipment. Environmental savings Closed Systems Equipment rental and operating Can handle H2S. Better cost Cannot be used with explosive monitoring returns. mixtures. Harold Vance Department of Petroleum Engineering Cost Comparisons ­ Case 1 Cost Comparisons ­ Case 1 Nitrogen vs. Pipeline Gas General Assumptions Flowrate…………………………………...3,000 cfm Gas Price……………………………… $2.00/mcf Trucking Distance……….... 50 miles (one way) Drilling Hours/day……………....………… …… 20 Average Gas Drilling Days/well…………… ….12 Diesel Usage/hour/unit…………….10.7 gallons Diesel Fuel Price…………………... $ 0.80/gallon Standby Days (Equipment)/well…..……......... 4 Harold Vance Department of Petroleum Engineering Cost Comparisons ­ Case 1 Cost Comparisons ­ Case 1 Nitrogen Drilling System Cost Pipeline Gas Drilling Cost Compressors (8) @ $135/unit/day $ 12,960 Pipeline gas 43.2 mmcf @ $2.00/mcf $ 86,400 Boosters (2) @ $200/unit/day (air $ 4,800 Booster (2) $300/unit/day (gas use) $ 7,200 $ 36,000 Drill Gas Unit (installed on location) $ 1,000 Gas Line (2,000 feet) $ 1,800 $ 20,540 Trucking/Transportation Fuel $ 1,800 Mist Pump $ 1,500 (delivered) 5,138 gallons @ $0.80/gallon $ 4,110 Equipment Standby (4 days) $ 1,800 Mist Pump $ 1,500 use) Membrane Skids (2) @ $1,500/unit/day (1,800 cfm/skid) Trucking/Transportation Fuel (delivered) 25,680 gallons * $0.80/gallon $ 9,200 Equipment Standby (4 days) Total Nitrogen Drilling Cost/well $ 88,600 Total pipeline Gas Drilling Cost/well Harold Vance Department of Petroleum Engineering $ 700 $ 104,510 Cost Comparisons ­ Case 2 Portable N2 Generating Item Liquid N2 Drilling Program 90 days N2 1,500 scfm 1,500 scfm Duration of N2 240 hrs (10 days) 240 hrs (10 days) N2 Purity Minimum 95 % (by Minimum 95 % (by volume) requirement N2 Pressure volume) 5,000 psi System 90 days 5,000 psi 1,500 scfm * 60 min/hr * 24 hr/day *10 days = N2 requirement 1,500 scfm * 60 min/hr * 584,000 sm3 24 hr/day *10 days = 584,000 sm3 = 834,000 liters liquid N2 = 139 tanks Method of N2 Supply Trucked in liquid N2 On­site membrane (equipment rental) (equipment purchase) Harold Vance Department of Petroleum Engineering Cost Comparisons ­ Case 2 Item Item Logistics Liquid N2 139 liquid N2 tanks, 1 evaporator and 1 diesel skid (141 containers) Cost of Utilities (liquid N2 , electricity, Portable N2 Generating System 4 skid maximum, 14 tonnes each, 1 power unit, 14 tonnes (5 containers) Electrical power: 1,400 kW * 10 days * 24 hrs @ $0.05/kWh $ 1,284,000 diesel) = $ 16,800 (Power unit rental included in Maintenance None Capital Cost None TOTAL capital cost) 10 % of interest and depreciation Approximately $ 1,300,000 Harold Vance Department of Petroleum Engineering $ 32,000 Interest and depreciation over 10 years $324,000 Approximately $ 375,000 Economic Analysis Economic Analysis • On the basis of available technology, select the potential drilling systems to be evaluated. • Tabulate the tangible and intangible costs for each system. • Rely on previous history and recognize the inevitability of statistical variation. Harold Vance Department of Petroleum Engineering Economic Analysis • Perform basic cost/ft drilling evaluations. CT = [B+Cr(t+T)] / F Where: CT……total cost/foot. B…….bit cost. Cr……hourly rig cost. t……..rotating time. T…….round trip time. F…….footage per bit run. Harold Vance Department of Petroleum Engineering (4.12) Assess Drilling Costs Assess Drilling Costs Item Air Drilling Mud Drilling Interval From 4,000 to 7,000 ft From 4,000 to 7,000 ft Interval Length (F) (ft) 3,000 3,000 Penetration Rate (ft/hr) 30 15 Rotating Time (t) (hr) 100 200 Bit Life (hr) 100 100 Bits Required 1 2 Unit Bit Cost $ 4,800/bit $ 4,800/bit Bit Cost (B) $ 4,800 $ 4,800 Trip Schedule Total Trip Footage Unit Trip Time (hr/1,000 ft) Trip in to 4,000 ft Trip out from 7,000 ft 11,000 ft 1.5 Harold Vance Department of Petroleum Engineering Trip in to 4,000 ft Trip out from 5,500 ft Trip in to 5,500 ft Trip out from 7,000 ft 22,000 ft 1.5 Assess Drilling Costs Assess Drilling Costs Item Air Drilling Mud Drilling Trip Time (T) (hr) 16.5 33 $ 375/hr $ 250/hr Hourly Operating Cost (Cr) Cost / ft [9,600+250(33+200)] / [3000] [B+Cr(T+t)]/[F] $ 22.62 /ft Competitive Cost for Air Drilling [4,800+Cr(16.5+100)] / [3000] = $ 22.62t Cr = $ 541.29/hr Barrels of Water That Can be Disposed of at ($541.29 ­ $375)/ $1.00 = $ 1.00/bbl Barrels of Water That Can be Disposed of at ($541.29 ­ $375)/ $5.00 = $ 5.00/bbl Barrels of Water That Can be Disposed of at ($541.29 ­ $375)/ $10.00 = $ 10.00/bbl 166 * 24 = 3,984 BWPD 33 * 24 = 798 BWPD 16.6 * 24 = 400 BWPD Harold Vance Department of Petroleum Engineering 25 24 23 Cost ($/ft) 22 21 20 19 18 17 16 15 0 500 1000 1500 2000 2500 3000 Barrels of Produced Water per Day Economic water volume production (modified after Carden 1993 1). Harold Vance Department of Petroleum Engineering Accelerated Production Accelerated Production • Earlier production can improve the NPV NPV = 1 / (1+DR)t = (1+DR)­t NPV = net present value (discounted value of asset). DR = discount rate. t = discount time, years. Harold Vance Department of Petroleum Engineering Improved Improved Production/Reserves • The absolute and relative increase in production should be calculated, or estimated. • Productivity Index, PI should be calculated based on whether the well is vertical, horizontal, oil, gas, radial, transient flow, or pseudo­ steady state flow (see page 4.48). Harold Vance Department of Petroleum Engineering Improved Production/Reserves • Well Inflow Quality Indicator, WIQI, is the ratio of the PI for an impaired to that for an undamaged well. Harold Vance Department of Petroleum Engineering Improved Production/Reserves Considering the evaluating PI: following example K 50 mD H 25 feet µ 2 cP Bo 1 bbl/sbbl re 1,980 ft rw 0.411 S variable Orientation vertical depth 10,000 ft reservoir pressure 4,300 psi BHPP 3,000 psi (pseudo­steady state) Harold Vance Department of Petroleum Engineering for Improved Production/Reserves Skin Skin Production Rate (BOPD) PI WIQI 0 761 0.572 1 1 674 0.507 0.89 2 604 0.455 0.79 5 462 0.348 0.61 10 331 0.249 0.44 100 55 0.041 0.07 Harold Vance Department of Petroleum Engineering Improved Production/Reserves 0.98 600 0.84 500 0.7 400 0.56 300 0.42 200 0.28 100 0.14 0 0 0 1 2 5 10 100 Well Inflow Quality Indicator Productivity Index 1.12 700 Production Rate (BOPD) 800 Skin Economic water volume production (modified after Carden 1993 1). Harold Vance Department of Petroleum Engineering Example Example Oil well Revenue Interest = R = 0.375 Working Interest = WI = 0.5 Gross Income (per net bbl) Crude Price = $20.00/bbl Less Transportation = $1.00/bbl Production taxes = $6.00/bbl Leaves Gross Income (per net bbl) = $13.00/bbl Estimated Op. Expense = $5000/well month Number of wells = 5 Harold Vance Department of Petroleum Engineering Case 1 Case 1 All five wells drilled in the first year with a conventional mud system. Harold Vance Department of Petroleum Engineering Case 1 (Base Case) Year Year Estimated Future (1) Gross Lease Production (2) Net Production To Operator (3) Gross Income 1 Operation bbl 3 4 5 6 7 Total Units ­ 2 (2) * $13.00 To Operator (4) Development 170,280 122,952 96,720 77,960 55,388 18,024 742,528 75,452 63,855 46,107 36,270 29,325 20,771 6,759 278,448 $ 980,870 830,115 599,391 471,510 380,055 270,017 87,867 3,619,824 $ R * (1) 201,204 750,000 bbl 0 0 0 0 0 0 750,000 Cost (5) Number of ­ ­ 60 60 48 48 36 36 24 312 (5) * $5,000 $ 300,000 300,000 240,000 240,000 180,000 180,000 120,000 1,560,000 Producing Well Months (6) Operating Expense Harold Vance Department of Petroleum Engineering Case 1 (Base Case) Year Year 1 Estimated Future 3 4 5 6 7 Total Units $ 20,000 20,000 20,000 20,000 20,000 20,000 20,000 140,000 $ 535,000 160,000 130,000 130,000 100,000 100,000 70,000 1,225,000 (3) – (8) $ 445,870 670,115 469,391 341,510 280,055 170,017 17,867 2,394,824 © Expenditure (8) Operation ­ (7) Capital ­ 0.9740 0.9276 0.8835 0.8414 0.8013 0.7632 0.7268 0.9010 (10) * (9) $ 434,277 621,599 414,707 287,347 224,408 129,757 12,986 2,157,736 WI * Share of [(4)+(6)+(7)] Operating and Capital Expenses (9) Cash Flow to Operator (10) 5% Annual Deferment Factor (11) Present Worth 2 Of Cash Flow © DCR= [(1+i)1­t – (1+i)­t] / 12[(1+i)1/12 ­1] DCR i t annual deferment factors, applicable to equal payments at the end of each month during a specific interval of year between (t­1) an t years from now. effective annual compound safe interest rate as a decimal fraction. time in years Harold Vance Department of Petroleum Engineering Case 2 Case 2 Same as Case 1 with the exception that there is higher production to reduced formation damage from UBD. Harold Vance Department of Petroleum Engineering Case 2 Year Year Estimated Future (1) Gross Lease Production (2) Net Production To Operator (3) Gross Income 1 2 3 4 5 6 7 Total Operation Units ­ bbl 221,324 187,308 135,247 106,392 85,756 60,927 19,826 816,781 R * (1) bbl 82,997 70,241 50,718 39,897 32,159 22,848 7,435 306,293 (2) * $13.00 $ 1,078,956 913,127 659,330 518,661 418,061 297,018 96,654 3,981,806 $ 750,000 0 0 0 0 0 0 750,000 ­ ­ 60 60 48 48 36 36 24 312 (5) * $5,000 $ 300,000 300,000 240,000 240,000 180,000 180,000 120,000 1,560,000 To Operator (4) Development Cost (5) Number of Producing Well Months (6) Operating Expense Harold Vance Department of Petroleum Engineering Case 2 Year Year Estimated Future (7) Capital Expenditure (8) Share of Operating and Capital Expenses (9) Cash Flow to Operator (10) 5% Annual Deferment Factor (11) Present Worth 1 2 3 4 5 6 7 Total Operation Units ­ $ 20,000 20,000 20,000 20,000 20,000 20,000 20,000 140,000 $ 535,000 160,000 130,000 130,000 100,000 100,000 70,000 1,225,000 (3) – (8) $ 543,956 753,127 529,330 388,661 318,061 197,018 26,654 2,756,806 © ­ 0.9740 0.9276 0.8835 0.8414 0.8013 0.7632 0.7268 0.9010 (9) * (8) $ 529,814 698,600 467,663 327,019 254,862 150,364 19,372 2,483,883 WI * [(4)+(6)+(7)] Of Cash Flow © DCR= [(1+i)1­t – (1+i)­t] / 12[(1+i)1/12 ­1] DCR i t annual deferment factors, applicable to equal payments at the end of each month during a specific interval of year between (t­1) an t years from now. effective annual compound safe interest rate as a decimal fraction. time in years Harold Vance Department of Petroleum Engineering Case 3 Case 3 Same as case 2 with the exception that development costs for the five wells are $150,000 less, due to improved drilling while underbalanced. Harold Vance Department of Petroleum Engineering Case 3 Year Year Estimated Future (1) Gross Lease Production (2) Net Production To Operator (3) Gross Income 1 Operation bbl R * (1) bbl (2) * $13.00 3 4 5 6 7 Total Units ­ 2 187,308 135,247 106,392 82,997 70,241 50,718 39,897 32,159 22,848 $ 1,078,956 913,127 659,330 518,661 418,061 297,018 $ 600,000 0 0 0 0 0 0 600,000 ­ ­ 60 60 48 48 36 36 24 312 (5) * $5,000 $ 300,000 300,000 240,000 240,000 180,000 180,000 120,000 1,560,000 To Operator (4) Development 221,324 85,756 60,927 19,826 7,435 96,654 816,781 306,293 3,981,806 Cost (5) Number of Producing Well Months (6) Operating Expense Harold Vance Department of Petroleum Engineering Case 3 Case 3 Year 1 Estimated Future 3 4 5 6 7 Total Expenditure (8) Units $ 20,000 20,000 20,000 20,000 20,000 20,000 20,000 140,000 $ 460,000 160,000 130,000 130,000 100,000 100,000 70,000 1,150,000 (3) – (8) $ 618,956 753,127 529,330 388,661 318,061 197,018 26,654 2,831,806 © Capital Operation ­ (7) ­ 0.9740 0.9276 0.8835 0.8414 0.8013 0.7632 0.7268 0.9010 (9) * (8) $ 602,864 698,600 467,663 327,019 254,862 150,364 19,372 2,551,458 WI * Share of [(4)+(6)+(7)] Operating and Capital Expenses (9) Cash Flow to Operator (10) 5% Annual Deferment Factor (11) Present Worth 2 Of Cash Flow © DCR= [(1+i)1­t – (1+i)­t] / 12[(1+i)1/12 ­1] DCR i t annual deferment factors, applicable to equal payments at the end of each month during a specific interval of year between (t­1) an t years from now. effective annual compound safe interest rate as a decimal fraction. time in years Harold Vance Department of Petroleum Engineering Summary of all Cases Summary of all Cases (Present Worth of Cash) Case Year 1 2 3 4 5 6 7 Total 1 434,277 621,599 414,707 287,347 224,408 129,757 12,986 2,157,736 2 529,814 698,600 467,663 327,019 254,862 150,364 19,372 2,483,883 3 602,864 698,600 467,663 327,019 254,862 150,364 19,372 2,551,458 Harold Vance Department of Petroleum Engineering Summary of Examples Summary of Examples 700,000 Present Worth of Cash Flow ($) 600,000 500,000 400,000 300,000 200,000 100,000 0 1 2 3 4 5 6 7 Year Projections Over Seven Years Harold Vance Department of Petroleum Engineering ...
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This note was uploaded on 10/30/2011 for the course PETROLEUM 689 taught by Professor Jeromej.schubert during the Fall '11 term at Texas A&M University-Galveston.

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