Energy Benchmarking Al Wakelin Sensor Environmental WHAT WE HAVE LEARNED
It is a Valuable Tool However, it must be adapted to this Industry
Adaptations Clusters Sour gas, Sweet Gas, Conventional Oil, Heavy Oil Fuel Gas Intensity Critical Unit Operations
Sweet Gas Average 200 20% Energy Intensity [GJ/e3GJ] 180 160 140 120 100 80 60 Fuel Gas Intensity= Energy of Fuel Gas Used Energy Produced from Gas & Liquids 18% 16% 14% 12% 10% 8% 6% Fuel Gas Intensity (%) 40 4% 20 2% 0 Jan-03 Jun-03 Nov-03 Apr-04 Sep-04 0% Source: EUB ST13 * every non-reported data has been excluded
Sweet Gas Plants and Field 200 20% Energy Intensity [GJ/e3GJ] 180 160 140 120 100 80 60 Fuel Gas Intensity= Total Energy of Fuel Gas Used Energy Produced from Gas & Liquids Plant Field 18% 16% 14% 12% 10% 8% 6% Fuel Gas Intensity (%) 40 4% 20 2% 0 Jan-03 Jun-03 Nov-03 Apr-04 Sep-04 0% Source: EUB ST13 * every non-reported data has been excluded
Sulphur Recovery Plant 200 20% 180 Fuel Gas Intensity= Energy of Fuel Gas Used at the Plant Energy Produced from Gas, Liquids and Sulphur 18% Fuel Gas Intensity (GJ/e3GJ) 160 140 120 100 80 60 Audit #2 Sulfur Recovery Plant Feb. 2003 Audit 2 Average SRU 16% 14% 12% 10% 8% 6% Fuel Gas Intensity (%) 40 4% 20 2% 0 0% Nov-2001 May-2002 Dec-2002 Jun-2003 Jan-2004 Aug-2004 Feb-2005 Time Period Source: EUB St13 2002-2004
Features Establish Baseline Performance Gauging Impact of Changes Compare Current Practice with Best Practices
Optimization Tool Ben Spooner Amine Experts Inc. Amine Plant Optimization Models
Optimization Model Purpose Energy audits revealed root cause of high energy usage in amine plants was from over circulation ( common thread ) More amine being sent to absorber than theoretically needed based on inlet H 2 S and CO 2 content Tool developed to help determine: If circulation rate can be reduced If not why not? Possible engineering study Cost of not reducing circulation rate 1 MW = 2.25 e 3 m 3 /day fuel gas = 4.7 t CO 2 /day
Amine Optimization Models result of GPSA calculations and simulation (ProTreat and HYSYS) results circulation rate = K(Gy/x) K = multiplication coefficient G = total gas flow y = total acid gas % (mol% H 2 S + mol% CO 2 ) x = amine concentration (wt %) reboiler duty: X% amine = K x (amine circulation rate) CIRCULATION RATE DIRECTLY AFFECTS REBOILER DUTY
40000 35000 MDEA Operating Model 3200 e 3 m 3 /d, 10% acid gas 50% 45% 40% 35% 100 Acid Gas (m ol % ) x Total Gas Volume (e3m 3/d) 30000 25000 20000 15000 10000 50% 45% 40% 35% 75 50 25 Reboiler Duty (M W ) 5000 0 0 100 200 300 400 500 0 Circulation Rate (m3/h) Circulation Rate (35%) Circulation Rate (40%) Circulation Rate (45%) Circulation Rate (50%) Reboiler Duty (35%) Reboiler Duty (40%) Reboler Duty (45%) Reboiler Duty (50%)
DEA Operating Model 40000 120 Acid Gas (mol %) x Total Gas Volume (e 3 m 3 /d) 35000 30000 25000 20000 15000 10000 5000 35 % 30% 25 % 20% 35% 30% 25% 20% 105 90 75 60 45 30 15 Reboiler Duty (MW) 0 0 100 200 300 400 500 600 700 800 0 Circulation Rate (m 3 /h) 20% DEA 25% DEA 30% DEA 35% DEA 20% 25% 30% 35%
Model Predictions circulation rate will sweeten gas to below spec of 4 ppm H 2 S and 2% CO 2 corrosion mitigation DEA rich loading of 0.45 0.55 (depending on partial pressures) rich loading of 0.45 for MDEA reflux ratios: DEA 1.5 MDEA 1.25 equivalent to overhead temperature of 100EC
Assumed Parameters contactor sized according to inlet gas volume & pressure regeneration tower sized according to amine circulation rate
Simulation Parameters inlet gas temperature inlet gas pressure: >2070 kpa / 300 psi lean amine temperature rich amine temperature (into regen tower) reflux temperature reflux pressure
Impact of Inefficiencies difference between the model predictions and actual plant conditions is: impact of inefficiencies or mechanical problems in the plant
20% DEA, 10% acid gas, 3200 10 3 m 3 /d 40000 120 Acid Gas (mol %) x Total Gas Volume (10 3 m 3 /d) 35000 30000 25000 20000 15000 10000 5000 35 % 30% 25 % 20% 35% 30% 25% 105 90 75 60 20% 45 22% 30 15 Reboiler Duty (MW) 0 22% 0 100 200 300 400 500 600 700 800 0 Circulation Rate (m 3 /h) 20% DEA 25% DEA 30% DEA 35% DEA 20% 25% 30% 35%
20% DEA, 10% acid gas, 3250 10 3 m 3 /d 40000 120 Acid Gas (mol %) x Total Gas Volume (10 3 m 3 /d) 35000 30000 25000 20000 15000 10000 5000 35 % 30% 25 % 20% 35% 30% 25% 20% 105 90 75 60 45 30 15 Reboiler Duty (MW) 0 0 100 200 300 400 500 600 700 800 0 Circulation Rate (m 3 /h) 20% DEA 25% DEA 30% DEA 35% DEA 20% 25% 30% 35%
Impact of Inefficiencies over-circulating amine can have the following negative effects increased: heat duty in all aerial coolers and reboiler pump duty wear and tear on all equipment and piping (causing corrosion and equipment failure) filter changes hydrocarbon absorption CO 2 pickup in MDEA systems
Model Verification taken onsite to various DEA & MDEA facilities very encouraging results any deviations from the graph were explainable generally, reboiler duty was correct for given circulation rate
Acid Gas (mol %) x Total Gas Volume (e 3 m 3 /d) ENERGY MANAGEMENT WORKSHOP 2007 6500 6000 5500 5000 4500 4000 3500 MDEA Operating Model Circulation Rate 40% MDEA 40 50 60 70 Circulation Rate (m 3 /h)
Heat Medium Flow (m3/h) 150 140 130 120 MDEA Operating Model Reboiler Heat Medium Flow 40% MDEA 110 50 60 70 Circulation Rate (m 3 /h)
Next Step inefficiencies need to be measured and trended over time data to be stored and displayed on DCS benefit of repairing inefficiency can be easily demonstrated
Current Performance vs. Recommended 50 % away from recommended 40 30 20 10 0-10 -20 Circulation rate $/MW = Reboiler Duty L/R exchanger efficiency Lean amine cooler duty Absorber Temperature Bulge Tray Flooding -30 Circulation rate L/R exchanger efficiency Absorber Temperature Bulge Reboiler Duty Lean amine cooler duty Tray Flooding
Summary makes operators life EASIER model prediction represents optimum operating point optimum KPI average plant over circulates by 20%: 200 amine reboilers x 10 MW x 20% reduction = 400 MW 400 MW = 900 e 3 m 3 /d fuel gas = $181 912 /d (based on 38.5 GJ/e 3 m 3 ) = $66.4 million/yr = 1 890 t CO 2 /day = 690 M t/yr
Case Study Rod Leland RCL Environment Group Glycol Dehydrator Optimization
Glycol Dehydrator Optimization Outline Glycol Dehydrator Operations Overview Energy Consumption EUB Environmental Emissions Standards Result in energy consumption reduction Operations Optimization, Emissions Reduction and Reduced Energy Consumption
Glycol Dehydration Schematic Dry Gas Flash Gas Water Vapour (with Benzene) Glycol Contactor Lean Glycol Still Reboiler Exhaust gas Wet Gas Rich Glycol Surge Drum Free Liquid
Glycol Dehydrator Optimization Natural Gas Used in: Glycol Pumps Chemical Pumps Reboiler Burner Reboiler (as Stripping Gas) Flares and Incinerators Often Used in Pumps Instead of Electricity
Glycol Dehydrator Optimization Glycol circulation rate: Often easily changed Often too high Directly impacts: Benzene Emissions CO 2 Emissions Energy Consumption
New Emission Regulations Drive Energy Conservation EUB Directive 39 s New Requirements: Lower Dehydrator Benzene Emission Limits Site Emission Limits Posting of Dehydrator Optimization Graph (DEOS) Annual Review of Operations of Every Dehydrator
DEOS Chart Circulation Rate Reduction: Benzene Emissions are reduced by 50% by applying a 50% Circulation Rate Reduction
DEOS Chart Circulation Rate Reduction: Benzene Emissions are reduced by 50% by applying a 50% Circulation Rate Reduction Dry Gas H 2 O Content Increased by 10%
Fuel Gas Reduction Fuel Gas Consumption by Glycol Circulation Rate Reducing Glycol Circulation Reduces Fuel Gas Use Fuel Gas Consumption E3M3 200 180 160 140 120 100 80 60 40 20 0 0 0.25 0.50 0.75 1.00 1.25 1.50 1.75 2.00 Circulation Rate GPM Burner Pump Gas
Glycol Dehydrator Optimization Dehydrator Statistics (2004) 2802 Oil and Gas Dehydrators in Alberta O&G Sector (82% of Canada s) Dehydrator Installation Types (~78% are all gas-driven) Wellsites 44% Compressors 34% Gas Plants 16% Batteries 6% Remote Sites - Significant Optimization Opportunity
Glycol Dehydrator Optimization Considerations: Optimization usually requires no capital expenditure Often Significant Energy Use Reductions Annual Review Required Continuous Improvement Improved Environment = Improved Economy
Methane Savings from Dehydrators and Compressors Energy Management Workshop for Upstream and Midstream Operations January 17, 2006
Agenda Dehydrators Glycol Circulation Rate Flash Tank Separators Compressors Reciprocating Compressors Centrifugal Compressors Discussion Topics Contact Information 41
Dehydrators: What is the Problem? Produced gas is saturated with water, which must be removed for gas transmission Glycol dehydrators are the most common equipment to remove water from gas Dehydration systems in natural gas production, gathering, and boosting Most use triethylene glycol (TEG) Glycol dehydrators create emissions Methane and other hydrocarbons from reboiler vent Methane from pneumatic controllers On average, 275 cubic feet (cf) of methane emissions per million cf of gas processed1 Source: www.prideofthehill.com 1 Methane Emissions from the Natural Gas Industry, Volume 14: Glycol Dehydrators, USEPA, June 1996. 42
Basic Glycol Dehydrator System Process Diagram Glycol Contactor Dry Sales Gas Inlet Wet Gas Water/Methane/VOCs/HAPs To Atmosphere Driver Gas Bypass Lean TEG Glycol Energy Exchange Pump Pump Rich TEG Glycol Reboiler/ Regenerator Fuel Gas VOCs = Volatile Organic Compounds HAPs = Hazardous Air Pollutants 43
Solution: Optimizing Glycol Circulation Rate Gas pressure and flow at gathering/booster stations vary over time Glycol circulation rates are often set at a maximum circulation rate Glycol overcirculation results in more methane emissions without significant reduction in gas moisture content Methane emissions are directly proportional to circulation Operators have found circulation rates two to three times higher than necessary Gas STAR Lessons Learned has calculations to optimize circulation rates, save gas 44
Solution: Installing Flash Tank Separator (FTS) Flashed methane can be captured using a FTS Many units are not using a FTS (see bar chart) Recovers about 90% of methane emissions Reduces volatile organic compounds by 10 to 90% Must have an outlet for low pressure gas Fuel Compressor suction Vapor recovery unit Percent With FTS Without FTS 100 80 60 40 20 0 MMcf = Million Cubic feet <1 1-5 >5 MMcf/day processed Source: API 45
Economics of Flash Tanks Capital and installation costs: Capital costs range from $6,750 to $13,500 per flash tank Installation costs range from $3,300 to $5,900 per flash tank Negligible operational & maintenance costs 46
Methane Savings: Dehydrators Two Options for Minimizing Glycol Dehydrator Emissions Option Optimize Circulation Rate Install Flash Tank Capital Costs Negligible $6,500 to $18,800 Annual Operational & Maintenance Costs Negligible Negligible Emissions Savings 130 to 13,133 Mcf/year 236 to 7,098 Mcf/year Payback Period 1 Immediate 4 to 11 months 1 Gas price of $7/Mcf 47
Industry Experience One operator routes gas from FTS to fuel gas system, saving 24 Mcf/day (8,760 Mcf/year) at each dehydrator unit Texaco (now Chevron) installed FTS Recovers 98% of methane from the glycol Reduced emissions from 1,232-1,706 Mcf/year to less than 47 Mcf/year 48
Agenda Dehydrators Glycol Circulation Rate Flash Tank Separators Compressors Reciprocating Compressors Centrifugal Compressors Discussion Topics Contact Information 49
Reciprocating Compressors: What is the Problem? Reciprocating compressor rod packing leaks some gas by design Newly installed packing may leak 60 cf/hour Worn packing has been reported to leak up to 900 cf/hour (Side View, Cut in Half) Cylinder Distance Piece Piston Rod Suction Piston OIL Rod Packing Case Discharge 50
Reciprocating Compressors: What is the Problem? A series of flexible rings fit around the shaft to prevent leakage Leakage may still occur through nose gasket; between packing cups; around the rings; and between rings and shaft Two Rings (In Three Segments) Lubrication Gas Leakage Flange Piston Rod High Pressure Gas Inside Cylinder Packing Cup Cylinder Wall Springs (Side View, Cut in Half) 51
Methane Savings Through Economic Rod Packing Replacement Assess costs of replacements A set of rings: $675 to $1,100 (with cups and case) $2,100 to $3,400 Rods: $2,500 to $13,500 Special coatings such as ceramic, tungsten carbide, or chromium can increase rod costs Assess the potential savings Monitor and record baseline packing leakage (usually on new packing) and piston rod wear Periodically compare current leak rate to initial leak rate to determine leak reduction expected Replace rod packing when the leak reduction expected is equal to or exceeds the economic replacement threshold 52
Solution: Rod Packing Replacement Economic Replacement Thresholds Rings Only Rods and Rings Rings: $1,620 Rings: $1,620 Rod: $0 Rod: $9,450 Gas: $7/Mcf Gas: $7/Mcf Operating: 8,000 hours/year Operating: 8,000 hours/year Leak Reduction Expected (cf/hour) Payback (years) Leak Reduction Expected (cf/hour) Payback (years) 32 17 12 9 1 217 1 2 114 2 3 79 3 4 62 4 Based on 10% interest rate 53
Centrifugal Compressors: What is the Problem? Centrifugal compressor wet seals leak little gas at the seal face Seal oil degassing may vent 40 to 200 cubic feet per minute (cf/minute) to the atmosphere High pressure seal oil circulates between rings around the compressor shaft Gas absorbs in the oil on the inboard side Little gas leaks through the oil seal Seal oil degassing vents methane to the atmosphere 54
Solution: Replace Wet Seals with Dry Seals Dry seal springs press the stationary ring in the seal housing against the rotating ring when the compressor is not rotating At high rotation speed, gas is pumped between the seal rings by grooves, creating a high pressure barrier to leakage Only a very small amount of gas escapes through the gap 55
Methane Savings: Dry Seals Dry seals typically leak at a rate of only 0.5 to 3 cf/minute Significantly less than the 40 to 200 cf/minute emissions from wet seals Gas savings translate to approximately $112,000 to $651,000 at $7/Mcf 56
Economics of Replacing Seals Compare costs and savings for a 6-inch shaft beam compressor Cost Category Dry Seal ($) Wet Seal ($) Implementation Costs 1 Seal costs (2 dry @ $13,500/shaft-inch, w/testing) $162,000 Seal costs (2 wet @ $6,7500/shaft-inch) $81,000 Other costs (engineering, equipment installation) $162,000 $0 Total Implementation Costs $324,000 $81,000 Annual O&M $14,100 $102,400 Annual Methane Emissions (@ $7/Mcf; 8,000 hours/year) 2 dry seals at a total of 6 cf/minute $20,160 2 wet seals at a total of 100 cf/minute $336,000 Total Costs Over 5-Year Period $495,300 $2,273,000 Total Dry Seal Savings Over 5 Years Savings $1,777,700 Methane Emissions Reductions (Mcf; at 45,120 Mcf/year) 225,600 1 Flowserve Corporation updated with Nelson Farrar indices 57
Discussion Topics Industry experience applying these technologies and practices Limitations on application of these technologies an practices Actual costs and benefits 58
Optimization Tool Brian Tyers Stantec Consulting Monitoring & Targeting Energy Usage
Monitoring and Targeting What you do not measure, you cannot control!! Tom Peters Monitoring and Targeting (M&T) is the backbone of any energy management program Energy savings, if not monitored, will quickly erode
Energy Use & Intensity Can Drift Normalized Energy Intensity, MJ/BOE 800 750 700 650 600 "Drift" Period Initial Energy Management Program Implementation of CUSUM 550 Oct Nov Dec Jan Feb Mar Apr May Jun
Steps Data collection Production; fuel, electrical energy Baseline selection Stable energy use pattern Used for gauging on-going performance
Steps Estimate of difference in energy use Actual energy use versus Predicted energy use Cumulative summation of differences (CUSUM)
Fuel Gas 2003-2005 500 Baseline Period 0-500 Apr Aug Dec Apr Aug Dec Fuel Gas CUSUM e 3 m 3-1,000-1,500-2,000-2,500-3,000 Period of Stantec Analysis Disc'n at Plant -3,500-4,000
Electrical 2003-2005 200,000 Baseline Period 0 Apr Aug Dec Apr Aug Dec Electricity CUSUM, kwh -200,000-400,000-600,000-800,000 Period of Stantec Analysis Disc'n at Plant -1,000,000-1,200,000
Tracking a Key Performance Indicator (Energy Intensity) 5,000 Baseline Initial Energy Management Steps CUSUM of Energy Intensity 0-5,000-10,000-15,000 Apr Jul Oct Jan May Aug Nov "Drift" in Energy Management Monitoring and Tracking Period of Best Performance -20,000
Total Energy 2003-2005 20,000,000 Baseline Period Total Energy CUSUM, MJ -20,000,000-40,000,000-60,000,000-80,000,000-100,000,000-120,000,000 0 Apr Aug Dec Apr Aug Dec Disc'n at Plant Period of Best Performance -140,000,000-160,000,000-180,000,000
Conclusions Identify the magnitude of energy use/wastage and associated emissions and their value at the Facility level Establish energy/emissions baselines and intensity indices Motivate Staff to manage energy usage, costs and emissions Budget More Accurately