wellbore management-preferred operating practices continued

2. The practices presented are based on: 1) Interviews with operators and service companies in the Permian Basin who successfully optimize water-handling costs,2)published practices in literature, and 3) writer’s personal experience in 31+years in the operating arena and 5 in consulting.The practices presented are based on: 1) Interviews with operators and service companies in the Permian Basin who successfully optimize water-handling costs,2)published practices in literature, and 3) writer’s personal experience in 31+years in the operating arena and 5 in consulting.

3. Chemicals protect inside of casing, tubing, and artifical lift systems; rods, esp, etc. Sacrificial anodes used to protect surface equipment Cathodic protection protect outside casingChemicals protect inside of casing, tubing, and artifical lift systems; rods, esp, etc. Sacrificial anodes used to protect surface equipment Cathodic protection protect outside casing

4. Successful chemical programs vary by operator but they all relate close to production volumes, a monitoring program, visual inspections, and maintaining a data base for evaluation. Remember using a surface coupon for metal loss detection from corrosion does not show corrosion accelerated by mechanical wear that would be seen downhole on the tubulars and pump. Good practice; if the rods are black when they are pulled there is an inhibitor film present. If they turn red hanging in the derrick the film is not there. Successful chemical programs vary by operator but they all relate close to production volumes, a monitoring program, visual inspections, and maintaining a data base for evaluation. Remember using a surface coupon for metal loss detection from corrosion does not show corrosion accelerated by mechanical wear that would be seen downhole on the tubulars and pump. Good practice; if the rods are black when they are pulled there is an inhibitor film present. If they turn red hanging in the derrick the film is not there.

5. The flush in batch treating is extremely important. Oil is the best to use, Keep oxygen out-if you have to use water try to use water from a gas blanketed tank-better yet to add oxygen scavenger.The flush in batch treating is extremely important. Oil is the best to use, Keep oxygen out-if you have to use water try to use water from a gas blanketed tank-better yet to add oxygen scavenger.

6. High fluid velocity in the tubing during pumping can prevent the corrosion inhibitor film on the rods around the couplings and rod guides if used. Under those conditions pretreatment is recommended. If you are pumping below a packer which doesn’t allow you to batch treat it is important to do the last step-displace the tubing with lease crude plus inhibitor. It is also recommended you lubricate sucker rod pins prior to make up ( not pipe dope) Use a combination lubricant oil-soluble corrosion inhibitor –80% oil 20% inhibitor. Spray or dip the pins to provide a light coating.High fluid velocity in the tubing during pumping can prevent the corrosion inhibitor film on the rods around the couplings and rod guides if used. Under those conditions pretreatment is recommended. If you are pumping below a packer which doesn’t allow you to batch treat it is important to do the last step-displace the tubing with lease crude plus inhibitor. It is also recommended you lubricate sucker rod pins prior to make up ( not pipe dope) Use a combination lubricant oil-soluble corrosion inhibitor –80% oil 20% inhibitor. Spray or dip the pins to provide a light coating.

8. Plain J-55 tubing is the choice of operators in beam pumping sucker rod wells with a corrosive environemnt. Tubing failures are internal from corrosion or rod wear, or external from buckling. Internal – corrosion inhibitor program or internal coatings. Some operators are using TK 99 plastic coating from the bottom joint up to the tubing anchor. Another operator uses a 316 stainless steel liner in the joint above the pump. Some operators are using plastic-coated tubing with ESPs. Cement lined tubing is still used in many fields although only in old wells. There is not a current push to use cement lined tubing. Polyethylene liners are becoming more and more popular. They work and are cheap. Will discuss this more later.Plain J-55 tubing is the choice of operators in beam pumping sucker rod wells with a corrosive environemnt. Tubing failures are internal from corrosion or rod wear, or external from buckling. Internal – corrosion inhibitor program or internal coatings. Some operators are using TK 99 plastic coating from the bottom joint up to the tubing anchor. Another operator uses a 316 stainless steel liner in the joint above the pump. Some operators are using plastic-coated tubing with ESPs. Cement lined tubing is still used in many fields although only in old wells. There is not a current push to use cement lined tubing. Polyethylene liners are becoming more and more popular. They work and are cheap. Will discuss this more later.

9. Most popular in corrosive enviroment is the kd, which is the Norris D rod 90 series. Some use EL rods if their corrosion programs are working. Fiberglass rods still used in specific cases; high fluid levels where the well producing capacity is greater than the lift equipment and the high fluid level prohibits inhibitor treatment; and where load is a big factor, whether it is a production volume load or a depth load.Most popular in corrosive enviroment is the kd, which is the Norris D rod 90 series. Some use EL rods if their corrosion programs are working. Fiberglass rods still used in specific cases; high fluid levels where the well producing capacity is greater than the lift equipment and the high fluid level prohibits inhibitor treatment; and where load is a big factor, whether it is a production volume load or a depth load.

10. There is a variety of composite metallugical pumps used in corrosive environments. Most popular are bronze/chrome barrel, brass/nickel carbide barrel or nicklet carbide coated barrel, brass internal, spray metal plungers, silica nitride balls, and nickel carbide seats. I am not a metallurgical specialist, only reporting what the majority of the operators are using for success. Othe considerations, especially for errosion wear, are the use of a vertical discharge pump and a blast joint in the tubing of the pump discharge area, whether it is a teflon coating, 316 ss liner, or polyethylene liner.. There is a variety of composite metallugical pumps used in corrosive environments. Most popular are bronze/chrome barrel, brass/nickel carbide barrel or nicklet carbide coated barrel, brass internal, spray metal plungers, silica nitride balls, and nickel carbide seats. I am not a metallurgical specialist, only reporting what the majority of the operators are using for success. Othe considerations, especially for errosion wear, are the use of a vertical discharge pump and a blast joint in the tubing of the pump discharge area, whether it is a teflon coating, 316 ss liner, or polyethylene liner..

11. The opinion of operators interviewed is to always anchor tubing in wells > 3000 feet, and should always anchor tubing regardless of depth to reduce tubing wear. Tubing rotators are hardly ever used anymore. If you anchor the tubing then the special anchor to allow rotation is complex and expensive.Omega has just introduced an inexpensive mechanical tubing rotator (about $1000) for shallow wells.The opinion of operators interviewed is to always anchor tubing in wells > 3000 feet, and should always anchor tubing regardless of depth to reduce tubing wear. Tubing rotators are hardly ever used anymore. If you anchor the tubing then the special anchor to allow rotation is complex and expensive.Omega has just introduced an inexpensive mechanical tubing rotator (about $1000) for shallow wells.

12. Use only as necessary is the opinion of interviewed operators. Fluid velocity around the rod guides reduces the corrosion inhibitor’s film. Use only where repeated tubing splits or excessive rold coupling wear occurs usually due to crooked drillled vertical wells and intentional deviated wells. Should run a deviation survey before installing.. Molded on guides are preferred over snap-on guides that require hammering and can produce nicks on the rod.Use only as necessary is the opinion of interviewed operators. Fluid velocity around the rod guides reduces the corrosion inhibitor’s film. Use only where repeated tubing splits or excessive rold coupling wear occurs usually due to crooked drillled vertical wells and intentional deviated wells. Should run a deviation survey before installing.. Molded on guides are preferred over snap-on guides that require hammering and can produce nicks on the rod.

13. Rod rotators are used to distribute coupling wear around the circumference of rod boxes and rod guides. Usually used only when rod guides are used. Rod rotators apply different torque for steel and fiberglass rods.Rod rotators are used to distribute coupling wear around the circumference of rod boxes and rod guides. Usually used only when rod guides are used. Rod rotators apply different torque for steel and fiberglass rods.

14. Very Popular-inexpensive-installed on used tubing-protects both corrosion and mechanical wear. Operators use the liners in different applications. Some run the liner in the joint above the pump; others use them in specific areas in the tubing string. Very Popular-inexpensive-installed on used tubing-protects both corrosion and mechanical wear. Operators use the liners in different applications. Some run the liner in the joint above the pump; others use them in specific areas in the tubing string.

15. This table shows the dimensions of the liners after installed in the tubing.This table shows the dimensions of the liners after installed in the tubing.

17. There is a new technology just developed in the past 9 months that shows the effect of polyethylene liners inside tubing. It is run on the rig floor and can be transmitted to a computer in an office. Expedites decision making on tubing replacement.There is a new technology just developed in the past 9 months that shows the effect of polyethylene liners inside tubing. It is run on the rig floor and can be transmitted to a computer in an office. Expedites decision making on tubing replacement.

19. Sucker rod failures due to improper makeup are backed by a lot of collected operating data and lab data. Published literature supports the necessity of proper sucker rod connection make up to minimize pin and coupling failures. There is a new technology developed, called the Black Box, that reads the pressure of the rod tongs and determines the proper torque make up. Sucker rod failures due to improper makeup are backed by a lot of collected operating data and lab data. Published literature supports the necessity of proper sucker rod connection make up to minimize pin and coupling failures. There is a new technology developed, called the Black Box, that reads the pressure of the rod tongs and determines the proper torque make up.

21. A beam pump system with a pump capacity that exceeds the well’s production can be operated with a timer or a pump-off controller (POC). These are sometimes referred to as “Rod Pump Controllers”. Beam-pumped sucker rod artificial lift systems are the most common means of producing oil and associated producted water. Why? Because these systems are relatively inexpensive, very efficient, easily repaired and there is a vast amount of knowledge about them. The major disadvantages of these sytems is the propensity for over-displacement, I.e., when the system is properly designed for load and stress, it will produce more fluid than the reservoir can yield. Hence we can get fluid pound. Fluid pounds cause damage and a waste of energy.A beam pump system with a pump capacity that exceeds the well’s production can be operated with a timer or a pump-off controller (POC). These are sometimes referred to as “Rod Pump Controllers”. Beam-pumped sucker rod artificial lift systems are the most common means of producing oil and associated producted water. Why? Because these systems are relatively inexpensive, very efficient, easily repaired and there is a vast amount of knowledge about them. The major disadvantages of these sytems is the propensity for over-displacement, I.e., when the system is properly designed for load and stress, it will produce more fluid than the reservoir can yield. Hence we can get fluid pound. Fluid pounds cause damage and a waste of energy.

22. Timers can be used to prevent fluid pound and reduce electrical costs, especially if a well has poor fluid-build, possibly due to poor downhole gas separation even with a high fluid level above the pump, and does not provide complete pump fillage on any stroke. They are inexpensive. A dynamometer survey needs to be made to determine if the well is a candidate for a POC, if not consider a timer.Timers can be used to prevent fluid pound and reduce electrical costs, especially if a well has poor fluid-build, possibly due to poor downhole gas separation even with a high fluid level above the pump, and does not provide complete pump fillage on any stroke. They are inexpensive. A dynamometer survey needs to be made to determine if the well is a candidate for a POC, if not consider a timer.

23. Reducing well failures, including practices to optimize artificial lift, vary from none to very disciplined well failure analyses and corrective action plans, proven to reduce failures. An example of “none” is when a rod parts , the operator pulls the well, replaces only the damaged rod, or when tubing fails, only the one tubing joint is replaced. Successful programs exist but they require a commitment from management/owner to fix the failure right.Reducing well failures, including practices to optimize artificial lift, vary from none to very disciplined well failure analyses and corrective action plans, proven to reduce failures. An example of “none” is when a rod parts , the operator pulls the well, replaces only the damaged rod, or when tubing fails, only the one tubing joint is replaced. Successful programs exist but they require a commitment from management/owner to fix the failure right.

24. Successful programs to reduce well failures all require an evaluation program and a correction action plan. Smaller operators need to employ the services of their support vendors, such as chemical, tubular, pump, and well servicing. Small operators also need to demand that their company representatives ( contract or company) are dedicated to the task of reducing well failures, and they should be involved in the evaluation and correction action plans.Successful programs to reduce well failures all require an evaluation program and a correction action plan. Smaller operators need to employ the services of their support vendors, such as chemical, tubular, pump, and well servicing. Small operators also need to demand that their company representatives ( contract or company) are dedicated to the task of reducing well failures, and they should be involved in the evaluation and correction action plans.

25. Well failure frequency averages for successful programs are under 1.0, which is 1 failure per year per well, whether a rod, tubing, or pump failure. Successful programs now have the frequency below 0.2. It requires a commitment as previousl stated. Next is a graph of one operator who reduced their well failures 10 fold over 10 years. Well failure frequency averages for successful programs are under 1.0, which is 1 failure per year per well, whether a rod, tubing, or pump failure. Successful programs now have the frequency below 0.2. It requires a commitment as previousl stated. Next is a graph of one operator who reduced their well failures 10 fold over 10 years.

52. BEAM PUMPING SYSTEMS ARE THE MOST POPULAR AND USUALLY THE LEAST EXPENSIVE SYSTEM FOR HANDLING PRODUCED WATER. IT IS IMPORTANT TO OPERATORS TO HAVE SYSTEM EFFICIENCY AND MINIMAL POWER COSTS. ONE PROGRAM USED IS ECHOMETER’S MODERN TOTAL WELL MANAGEMENT SYSTEM-TAKES INPUT FROM 3 SOURCES-ELECTRIC MOTOR, FLUID LEVEL, AND THE POLISH ROD SENSOR. THESE ARE FED INTO A COMPUTER PROGRAM THAT EVALUATES THE ENTIRE SYSTEM. TAKES ABOUT 45 MINUTES. SYSTEM EFFICIENCY INCREASES ARE SIGNIFICANT IN SAVINGS IN POWER USAGE. THE OVERAL SYSTEM EFFICIENCY IS DEFINED AS THE AMOUNT OF THEORETICAL WORK REQUIRED TO LIFT THE LIQUID FROM THE NET LIGUID LEVEL DEPTH TO THE SURFACE DIVIDED BY THE AMOUNT OF POWER SUPPLIED TO THE MOTOR.BEAM PUMPING SYSTEMS ARE THE MOST POPULAR AND USUALLY THE LEAST EXPENSIVE SYSTEM FOR HANDLING PRODUCED WATER. IT IS IMPORTANT TO OPERATORS TO HAVE SYSTEM EFFICIENCY AND MINIMAL POWER COSTS. ONE PROGRAM USED IS ECHOMETER’S MODERN TOTAL WELL MANAGEMENT SYSTEM-TAKES INPUT FROM 3 SOURCES-ELECTRIC MOTOR, FLUID LEVEL, AND THE POLISH ROD SENSOR. THESE ARE FED INTO A COMPUTER PROGRAM THAT EVALUATES THE ENTIRE SYSTEM. TAKES ABOUT 45 MINUTES. SYSTEM EFFICIENCY INCREASES ARE SIGNIFICANT IN SAVINGS IN POWER USAGE. THE OVERAL SYSTEM EFFICIENCY IS DEFINED AS THE AMOUNT OF THEORETICAL WORK REQUIRED TO LIFT THE LIQUID FROM THE NET LIGUID LEVEL DEPTH TO THE SURFACE DIVIDED BY THE AMOUNT OF POWER SUPPLIED TO THE MOTOR.

53. This is a graphical interpretation of system efficiency versus water cut versus lifting costs. It can be seen how lifting costs are reduced when system efficiency is increased. This is a graphical interpretation of system efficiency versus water cut versus lifting costs. It can be seen how lifting costs are reduced when system efficiency is increased.

55. Weatherford’s comparison of artificial lift methods, illustrates that for onshore, beam pumping or electrical submersible pumping is most common. There is an electrical submersible progressing cavity pump system developed by Centrilift, but its use has not been documented. Progressive cavity pumps are not widely usd in handling large amounts of produced water because of difficulties in combating corrosion and depth limitations. There is software available for artificial lift evaluations from Data Enterprises, at a cost of approximatley $4000.Weatherford’s comparison of artificial lift methods, illustrates that for onshore, beam pumping or electrical submersible pumping is most common. There is an electrical submersible progressing cavity pump system developed by Centrilift, but its use has not been documented. Progressive cavity pumps are not widely usd in handling large amounts of produced water because of difficulties in combating corrosion and depth limitations. There is software available for artificial lift evaluations from Data Enterprises, at a cost of approximatley $4000.

56. POLY PIPE IS THE MOST POPULAR FOR LOW PRESSURE USEPOLY PIPE IS THE MOST POPULAR FOR LOW PRESSURE USE

61. Today more operators are using less chemicals for processing, cold treating also. Newer facilities are being designed for additional retention time, using FWO’s, gunbarels, separators, or raw and clear water tanks. Still getting fairly clean water at 20-40ppm. Today more operators are using less chemicals for processing, cold treating also. Newer facilities are being designed for additional retention time, using FWO’s, gunbarels, separators, or raw and clear water tanks. Still getting fairly clean water at 20-40ppm.