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Perforating design

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Perforations from shaped charges (the most common method) are tapering tubes of usually less than 0.8 in. (2 cm) diameter at the entrance hole in the casing and depth of 1 in. (2.5 cm) to more than 30 in. (74 cm). Primary flow from the formation is through the end and walls of the tube. Flow behavior typically is dominated by radial flow with some pseudoradial character in longer perforations. Length, diameter, and permeability of the rock around the perforation control flow through a perforation.[1]

Basic perforating design

Many early studies ignored the damage around the perforation tunnel and focused on the importance of length and entrance hole diameter. Putting damage effects aside, the length of the perforation tunnel is theoretically the most critical factor in a natural completion in which no further stimulation or sand control is planned. Entrance hole diameter becomes more important when some sand control completion designs are planned or fracturing is needed. Because of the early studies that ignored the effects of formation damage, the primary selling points of perforating charges became perforated length and entrance hole diameter. These two elements diminish in significance when the effect of formation damage is studied.[2][3][4]

Perforating charge performance in producing both entrance hole and perforation length is related more closely to charge design than charge size. The charge variables include:

  • Propellant type
  • Propellant size
  • Propellant design

The formation variables[5] include:

Perforating charge power is provided by the explosive and focused by the case and liner to produce a jet. The jet may be shaped to maximize either entrance hole or tunnel penetration. The completion type dictates the type of perforation needed and thus the type of charge. No matter which charge is selected, however, the flow path must have a higher flow capacity than the formation can supply. Otherwise, it becomes a restriction in the reservoir-to-wellbore connection. Flow connection should be the primary consideration when selecting a perforating charge. Charge penetration can be optimized for specific nonpermeable targets such as cement and may produce a phenomenally long perforated length and very low flow capacity. Flow capacity should be the requirement in any producing environment.

As the jet penetrates the formation, the material in its path is thrust to the side, creating a zone of lowered permeability. The amount of permeability loss depends on the structure, porosity, and fluid of the formation and the size and design of the charge.

Studies of permeability loss in targets and back calculation of damage in relatively homogeneous formations show permeabilities of approximately 35 to 80% of the initial formation permeability. There are three critical requirements to achieving a highly conductive flow path:[1][6][7][8][9][10][11][12]

  • Select the optimum perforating equipment (including, but not limited to, charges) for the completion type
  • Select the fluids and charge for the best formation interaction (minimize damage)
  • Use the application method (underbalance, overbalance, surging, etc.) that provides the best cleanup and flow capacity in the perforations.

Design considerations

The best-known design considerations for perforating are:

  • Perforation length
  • Shot-phase angle
  • Perforation density
  • Entrance hole size
  • Perforating flow efficiency.

Design parameters

To design properly for optimum perforating requires preplanning and consideration of parameters such as:

  • Filtered perforating fluid
  • Amount of underbalance or overbalance
  • Tubing vs. casing
  • Expendable guns, the method for conveying guns, and gun clearance.

Special considerations, such as ultrahigh compressive strength rock (> 30,000 psi UCS), require special charges.[13]

Temperature effect

The higher the wellbore temperatures, the shorter the time that the perforating jet charge is stable. Fig. 1 illustrates stable time at temperature for charges made from common types of explosives. Guidelines for high-temperature charge selection vary, but most wireline-conveyed charges should be stable at the temperature for 16 to 24 hours. Tubing-conveyed perforating charges, for operations involving extended time at the bottomhole temperature, must remain stable for approximately 100 hours or more to allow for running the tubing and nippling up the wellhead. Higher temperature charges for operations involving extended time at temperatures greater than 300°F (149°C) are available, although they are more costly. When selecting a high-temperature charge, all parts of the system must be rated for the time at temperature and must work together, including:

  • Detonator
  • Detonation cord
  • Charges
  • Seals
  • Mechanical components

When perforating charges explode low order or burn, large fragments of the charge cases will remain. These fragments are primary evidence of the problem. Fig. 2 shows charged cases removed from a low-order gun. Gun breaches during low-order detonation or burning are common. Fig. 3 shows a burst gun fished from a well after low-order firing. Anytime whole charge cases or large sections of charge cases are found in the gun debris, the perforating job quality is highly suspect, and the perforating task should be evaluated or redone.

Optimum flow path

Before selecting components for a perforating job, the first task is to understand how to get the best flow path possible for the time and money invested and the risk taken. The amount of flow capacity needed must be determined first. Flow capacity needs are a reflection of how much and what type of fluids that the formation can deliver to the wellbore. Inflow performance modeling with representative values of formation permeability and fluid viscosity is necessary. The objective of perforating is to place open perforations at the correct depth that extend through the casing and cement sheath into the formation. To be effective, the perforation tunnel must be in contact with a permeable part of the formation and must not be damaged by any mechanism that would stop or impede the transfer of fluids between the formation and the wellbore.[2][14][15]

Optimizing petroleum production is an exercise in removing pressure drops in a flowing system that stretches from the outer boundaries of the reservoir to the sales line. The perforating process is one element in this engineering exercise. To optimize the whole process, the most severe pressure drops must be examined and removed. As each pressure drop is reduced, the increased flow may change the requirements in another section of the well. Increasing the flow capacity of the reservoir by stimulation or flooding places a greater capacity requirement on the perforations. Other well completion actions, such as gravel packing, change the flow requirement on the perforation by filling the perforation with gravel. Each action changes the criteria for perforation design; therefore, initial perforating designs may not be optimal for later well production. Well design should allow for flexibility in the completion type, which allows for adding perforation density in a zone or perforating other zones after the well has been evaluated or produced.

Perforator phasing

Phasing is the angle between the charges, and Fig. 4 shows a common perforator phasing. Although there are many possible angles, the five common values are:

  • 180°
  • 120°
  • 90°
  • 60°

0° phasing aligns all the shots in a row. The gun should be decentralized, typically against the low side of the casing, so that performance from small charges is maximized by minimizing the clearance between the gun and the casing wall. 0° phasing normally is used only in the smaller outside diameter (OD) guns or guns in very large casing. 0° phasing has some drawbacks because putting all the shots in a row lowers tubular yield strength and makes the casing more susceptible to splits and collapse at shot densities greater than 6 SPF. Fracture stimulating in wells that were perforated with 0° phasing may result in a slightly higher incidence of fracturing screenouts than with 60°, 90°, or 120° phasing. It is unknown whether the screenouts result from the smaller entrance holes or from one wing of the fracture wrapping around the pipe.

Of the other common phasing possibilities, 60°, 90°, and 120° are usually the most efficient choices from a fracture stimulation standpoint because they will produce a perforation just a few degrees from any possible fracture direction. These phased carriers may not need to be centralized to give good perforations because, regardless of where they contact the casing, at least two or three optimum perforations per foot should be formed. In small carrier guns in large casing, only 0° phasing should be used because the perforations closest to the gun will be fully developed, while the perforations with the largest gun clearance will be shorter and have a very small diameter. Casing guns offer much better phasing but often cannot be used to add perforations in an existing completion without major intervention.

Perforating phasing is known to affect production in both theoretical and practical applications. Locke, for example, showed that for a 12-in. penetration into the formation, a theoretical productivity ratio of 1.2 is predicted from 90° phasing of 4 SPF, while the productivity ratio is approximately 0.99 when the 4 shots are in 0° phasing.1 This is ideal behavior and does not consider damage. When damage is considered, the actual formation character and perforation application details may create a much different outcome, although the effect of additional phasing is usually beneficial.

Perforation length

Perforation length usually is thought to be the most important characteristic in a perforation design. Surprisingly, there are several cases in which perforated length does not make a significant difference in well productivity. Only in natural completions does the perforation tunnel length dominate the other factors. Even in natural completions, the flow capacity of the perforated connections is the most important factor. Factors such as hydraulic fracturing or prepacked gravel-pack operations negate the advantages of a few extra inches of perforated length. For hydraulic fracturing or gravel-pack treatments, a large, effective entrance hole through the pipe and cement is more important than total perforation penetration.

Perforation diameter

Although rarely considered, the perforation diameter also may influence the productivity ratio, especially in high productivity wells. Perforation diameter is dependent on charge design and the clearance of the gun in the casing. In instances such as sand control operations, unstable formations (including some chalks), and wells that are to be hydraulically fracture stimulated, the perforation diameter is important enough to dominate perforator selection. Flow through an open perforation should not be a restriction in the flowing system.

The choice between penetration length and entrance hole size is made available by the size of the charges and an element of the charge design. A charge’s design affects the hole diameter and penetration. Fig. 5 shows deep penetrating and big-hole charge performances from 34-g charges.

A deep-penetrating charge has a different shaped liner (and sometimes a different case) from that of a big-hole charge. The deep-penetrating charge spends the bulk of its energy creating a long tunnel, while the big-hole charge focuses its energy on the casing wall and creating hole diameter. Deep-penetrating charges normally are used in natural completions, and big-hole charges are used more for gravel packing and fracturing, in which hole size offers less restriction to wither outflow during fracturing or inflow during production when the perforation is filled with gravel. Big-hole charges may have some disadvantages in both pipe and formation strength. The design of big-hole charges produces maximum force impact at the wall of the casing and can cause damage (and weakening) to the formation adjacent to the entry hole. For completions in weak formations in which sand production could be an issue and gravel packing or frac packing will not be used, deep penetrating charges at high density (12 to 16 SPF or 39 to 54 SPM) are recommended. If the zone collapses, however, reperforating with sufficient density of phased shots is required before gravel-pack operations are instituted.

Number of perforations

The number of perforations is always a factor in completion design. Shot densities from 1 to 27 SPF (3 to 88 SPM) are available. High shot densities usually are required for very high flow rate formations, for single point application of fractures in deviated wellbores, and for laminated formations that will not be linked by fracturing. Optimum shot density for a well can best be determined with a nodal analysis simulator; however, judgment is needed when dealing with highly laminated formations or when the formation flow path is suitably inhomogeneous to create limited entry effects in the inflow. Adding perforations is often an excellent diagnostic tool.

Assuming all perforations are open to flow, shot densities of 4 SPF (13 SPM) with 90° phasing and with 13-mm (0.5-in.) holes usually are sufficient to ensure the equivalent of openhole productivity. However, increased shot densities (greater than 4 per foot) may improve productivity ratios under certain conditions, such as very high flowrate wells or in gravel-packed wells.

The real number of open perforations, those producing or taking fluid, is typically only approximately 50% of the total holes in the pipe. (The 50% value was reached after examining hundreds of hours of downhole television recordings in dozens of wells.) The cause of nonfunctioning perforations is usually traced to nonproductive layers in the formation or to damaged perforations. Perforating produces a damage zone around the perforation in which permeability may be reduced substantially below that of the native state formation. Longer perforations are less influenced by the crush zone than are short perforations. Phased perforations, such as 90° phased perforations, are less affected than 0° phased perforations. The damage in the near wellbore, plus the damage in the crushed zone, can cause severe pressure drops. However, most damage from drilling mud is confined near the face of the formation. In cases of nonwater-sensitive sandstones, the damage zone should not be of significance. The crushed zones will be created regardless of damage but may be minimized by underbalance or extreme overbalance perforating.

Improving flow capacity

Creating a perforation is relatively easy. Creating a low-pressure-drop flow path requires considerably more effort. As previously stated, most perforations have a crushed zone and other damage mechanisms that hinder production. To improve flow capacity, underbalanced perforating, extreme overbalanced perforating, surging, or one of several breakdown actions is necessary to clean the perforations and improve flow capacity.

Overbalance perforating

In most cases, overbalanced perforating drives the wellbore fluid into the perforation and has the capacity to create particulate damage in the perforations. Clean fluid becomes a perforating requirement. Studies of the flow rate needed to remove damage report that serious perforation plugging occurs when the pressure is higher in the wellbore than in the formation. These plugs consist of:

  • Crushed formation
  • Liner particles
  • Case material from the charges
  • Pipe dope
  • Mud

In many lab and field cases, a plug formed when overbalance perforating in heavy mud is almost impossible to remove by reversing pressure.

Extreme overbalance perforating

Extreme overbalance perforating (EOP) is a microfracture-initiating process that is applied at the moment of initial perforating or as a surge process to existing perforations.[16][17] The technique uses stored gas energy in the tubing to break down the zone. Bottomhole pressure equivalents to 1.4 psi/ft and higher are applied instantaneously through the use of a nitrogen gas supercharge contained in the tubing. The energy is isolated in the tubulars of an unperforated well and behind a shear disk or other device in the tubing on a well that has already been perforated. The energy imparted is more sudden than a traditional hydraulic fracturing process and more sustained than an explosive or propellant treatment.

The fracture created by the EOP surge is more likely to fracture more perforations in an exposed zone than a traditional fracture process applied as an all-liquid hydraulic-fracturing process. Work with production logs and radioactive-isotope-tagged sand after EOP jobs indicates that multiple zones tend to break down more evenly when EOP is used. Although a fracture is created during extreme overbalance perforating or surging, its initiation does not appear to be controlled initially by formation stresses or traditional rock mechanics forces, probably because the 1.4 psi/ft gradient is considerably greater than most fracture gradients of 0.7 to 0.9 psi/ft. Because of the very high pressure of the initial surge, the pressure behind the surge is probably greater than the fields of maximum and minimum principal stresses in the formation. As a result, the initial direction of the fracture is in the plane of greatest mechanical near-wellbore weakness: the perforations. After the estimated 6-second life of the pulse, the fracture direction probably is controlled by the traditional stress forces, and subsequent fracture growth goes perpendicular to the plane of least principal stress.

Although treatment designs are still being refined, the initial successes have focused on maximizing the kinetic energy in the job. This is accomplished by minimizing the liquid in the tubing to eliminate friction pressure of liquid movement during the surge. Most job designs focus on filling the tubing with nitrogen and filling the casing below the packer with liquid.

A modification of the EOP process uses explosive propellant to deliver a pressure pulse that achieves the same type of breakdown as the fluid, but with minimum equipment.28 The propellant is molded into a sleeve that is mounted on the outside of the perforating gun when adding perforations or as a stick when pulsing old perforations. Firing the perforating gun ignites the slower burning propellant, creating a gas pulse that breaks down the perforations. The pressure pulse lasts only a few seconds, but its location at the perforations helps break down crush zone damage. Fractures created by either the EOP or propellant process are not propped and will likely close after the event if not propped. The cleanout benefits of the process, however, have been well documented.


Surging perforations to achieve cleanup is an effective tool provided that the differential pressure is high enough to create enough fluid movement to clean the perforations. Few guidelines exist on surging other than at the local field level. Surges from 500 to 2,000 psi are common and are applied as suddenly as possible. The surges are most effective when the “valve” for the process is close to the formation. Long, small inside diameter tubing strings dampen the surge effectiveness because of high flowing friction resistance during the surge flow. Typically, not all perforations are opened by surging.

Cement and casing damage

Casing and cement damage during perforating has been debated for years.[18][19][20][21][22][23][24] There is probably little shattering or cracking damage to a good cement sheath from perforating. Tests have been conducted on more than 50 targets with unconfined compressive strength from 1,500 to more than 9,000 psi. When the perforation is more than approximately 4 in. from a free face (top or bottom of the target), there is almost no instance of cement shattering noted after firing. Splitting (longitudinal) along the perforated planes is seen in some targets but is an artifact of the test. In surface tests, cement cracking following perforating is the result of the test method, not the perforating process.

Either the casing or the carrier must absorb the explosive shock of charge detonation. Air-filled hollow-carrier guns absorb most of the detonation pressure; therefore, there is less possibility of casing splits caused by rupture. This becomes very important when shooting a large number of holes or whenever casing strength is important. The collapse resistance of the casing (and resistance to splits) depends on the number of holes in the pipe, the hole size, and their alignment (shot phasing). Casing guns with staggered phasing have improved the casing collapse resistance loss. These guns, which use deep-penetrating charges, often result in less than 10% casing strength crush resistance loss at shot densities of 16 or more SPF. Perforating with hollow-carrier guns causes only slight reduction in yield or collapse strength of the casing. Expendable and semiexpendable guns cause substantially more damage because the casing must stand the shock of detonation. Casing of low or unknown strength (corroded, old, flawed, or poorly supported casing) definitely should be shot with a hollow-carrier gun.

Gunshock simulation - Prediction of tools damage

The ability to predict and reduce large perforating gunshock loads (dynamic shock loads) and the associated risk of damage and non-productive time is very important because of the high cost of most wells, especially deepwater high-pressure wells.

Both low- and high-pressure wells are susceptible to gunshock damage when they are perforated with inappropriate gun systems and/or under adverse conditions. Computer simulation helps engineers identify perforating jobs with significant risk of gunshock damaged, such as bent tubing and unset or otherwise damaged packers, gun damage, wireline weak-point pull-offs, etc. When the predicted risk of gunshock damage is large, engineers can make changes to the perforating equipment or job execution parameters to reduce gunshock loads and the associated risk of equipment damage and non-productive time. With the available gunshock software, engineers can also evaluate the sensitivity of gunshock loads to changes in the perforating equipment, such as: gun type, charge type, shot density, tubing size and length, rathole length, and placement/setting of packers and shock absorbers.

The following papers describe the main sources of gunshock loads, typical dynamic loads on tubing and packers, and the loads that can lead to equipment damage. Simulation examples illustrate how to reduce gunshock loads by modifying the equipment used, and how small changes that cost very little to implement can lead to a large reduction in both gunshock loads and the associated risk of equipment damage.

References [25][26][27][28][29][30][31]

Perforating multiple strings and thick cement

Concentric casing strings reduce the penetration of any perforating charge.[32][33] The thickness of the extra string of casing, as well as the thickness of the two sheaths of cement that must be penetrated, reduces the perforation penetration length. In severe cases of small liners set through larger pipe, such as 5-in. liner cemented in 9 5/8-in. casing, perforating both strings is considerably more difficult. For the best chance of perforating multiple strings, the largest, best designed deep-penetrating charge that can be run will generally have the best chance of penetrating through all the strings and into the formation.[23] Through-tubing guns are not recommended for shooting concentric strings because hole size and penetration are reduced with small charges.

In deviated wells in which concentric strings are to be perforated, the perforating gun will ride the low side of the pipe. When a casing gun is used for this operation, shot phasing of 60°, 90°, or 120° should be used to obtain the best chances of making perforations by the charges with the least clearance. The use of centralization techniques (if possible) on the guns run in deviated wells are recommended if hydraulic fracturing is to be used. This allows perforations to be placed near both fracture wings. Centralization also improves the roundness of the holes because the gun clearance will be near ideal. If inadequate perforations are a problem in wells with concentric strings, the innermost casing can be milled out (albeit at great expense) and the completion made through the outer casing.

When casing is run and cemented through washed-out sections, the cement sheath can be sufficiently thick to deny access to the formation with any perforator. When drilling a well into an easily washable pay zone, care must be taken to obtain a gauge or near-gauge hole so that the perforations will reach into the pay.

Perforating in highly deviated wells

The perforating design needed for a cased and cemented highly deviated (greater than approximately 60°) well may be different from the design needed for a vertical well, even in a similar formation. The main factors are:

  • Placement of guns
  • Cost of perforating in very long sections
  • Need to produce selectively from a certain section of the wellbore
  • Coning control
  • Need for focusing injected fluid into a single interval when fracturing or acidizing

The number of perforations needed for well production, either deviated or vertical, depends on the inflow potential. Perforating costs can increase as pay contact increases, leading to reduced perforation density. A better method of perforating cost control is to use logging methods to identify zones of best porosity, oil saturation, and pressure (or flow in which production logging tool data are usable), and concentrate perforations in those areas. Leaving unperforated sections in a highly deviated or horizontal well also gives remedial operations such as plug setting a much better chance for success.

Fracturing in deviated wells requires a decision of whether to perforate the whole zone or to concentrate the perforations to ensure a single fracture breakdown. There is disagreement on the importance of numerous perforations in initiation of “starter fractures” formed in highly perforated zones. Localizing perforations can control the point of fracture initiation. Field performance has shown that perforating at 8 to 16 SPF over a 2- to 5-ft interval is sufficient to initiate a fracture. In field application of multiple fractures in deviated wells, perforating 3 ft (approximately 1 m) of the wellbore before each fracture job has produced good results. Although this approach is effective in providing sufficient wellbore contact with the main fracture to prevent early screenout, it does not address potential inflow from the unfractured matrix pays into the cased and cemented wellbore. Adding perforations along the length after all fracturing is one option, but obtaining any type of cleanup or breakdown of these added perforations can be accomplished only with a straddle packer.


  1. 1.0 1.1 Locke, S. 1981. An Advanced Method for Predicting the Productivity Ratio of a Perforated Well. J Pet Technol 33 (12): 2481-2488. SPE-8804-PA.
  2. 2.0 2.1 McLeod, H.O.J. 1983. The Effect of Perforating Conditions on Well Performance. Journal of Petroleum Technology 35 (1): 31–39. SPE-10649-PA.
  3. Hong, K.C. 1975. Productivity of Perforated Completions in Formations With or Without Damage. J Pet Technol 27 (8): 1027-1038. SPE-4653-PA.
  4. Klotz, J.A., Krueger, R.F., and Pye, D.S. 1974. Maximum Well Productivity in Damaged Formations Requires Deep, Clean Perforations. Presented at the SPE Symposium on Formation Damage Control, New Orleans, Louisiana, 30 January-2 February 1974. SPE-4792-MS.
  5. Brooks, J.E., Yang, W., and Behrmann, L.A. 1998. Effect of Sand-Grain Size on Perforator Performance. Presented at the SPE Formation Damage Control Conference, Lafayette, Louisiana, 18-19 February 1998. SPE-39457-MS.
  6. Bell, W.T. 1982. Perforating Techniques for Maximizing Well Productivity. Presented at the International Petroleum Exhibition and Technical Symposium, Beijing, China, 17-24 March 1982. SPE-10033-MS.
  7. Bell, W.T. 1984. Perforating Underbalanced Evolving Techniques (includes associated papers 13966 and 14140 ). J Pet Technol 36 (10): 1653-1662. SPE-13413-PA.
  8. King, G.E., Anderson, A., and Bingham, M. 1986. A Field Study of Underbalance Pressures Necessary To Obtain Clean Perforations Using Tubing-Conveyed Perforating. J Pet Technol 38 (6): 662-664. SPE-14321-PA.
  9. Young, W.S. and Zaleski Jr., T.E. 1985. Procedural Design Considerations Associated With Tubing-Conveyed Underbalanced Perforating. Presented at the SPE California Regional Meeting, Bakersfield, California, 27-29 March 1985. SPE-13646-MS.
  10. Halleck, P.M. and Deo, M. 1989. Effects of Underbalance on Perforation Flow. SPE Prod Eng 4 (2): 113-116. SPE-16895-PA.
  11. Regalbuto, J.A. and Riggs, R.S. 1985. High Differential Pressure, Radial Flow Characteristics of Gun Perforations. Presented at the SPE Annual Technical Conference and Exhibition, Las Vegas, Nevada, 22-26 September 1985. SPE-14319-MS.
  12. Bonomo, J.M. and Young, W.S. 1985. Analysis and Evaluation of Perforating and Perforation Cleanup Methods. J Pet Technol 37 (3): 505-510. SPE-12106-PA.
  13. Smith, P.S., Behrmann, L.A., and Yang, W. 1997. Improvements in Perforating Performance in High Compressive Strength Rocks. Presented at the SPE European Formation Damage Conference, The Hague, Netherlands, 2-3 June 1997. SPE-38141-MS.
  14. Saucier, R.J. and Lands, J.F.J. 1978. A Laboratory Study of Perforations in Stressed Formation Rocks. J Pet Technol 30 (9): 1347–1353. SPE-6758-PA.
  15. Behrmann, L.A., Li, J.L., Venkitaraman, A. et al. 1997. Borehole Dynamics During Underbalanced Perforating. Presented at the SPE European Formation Damage Conference, The Hague, Netherlands, 2-3 June 1997. SPE-38139-MS.
  16. Handren, P.J., Jupp, T.B., and Dees, J.M. 1993. Overbalance Perforating and Stimulation Method for Wells. Presented at the SPE Annual Technical Conference and Exhibition, Houston, Texas, 3-6 October 1993. SPE-26515-MS.
  17. Behrmann, L.A. and McDonald, B. 1999. Underbalance or Extreme Overbalance. SPE Prod & Oper 14 (3): 187-196. SPE-57390-PA.
  18. Godfrey, W.K. and Methven, N.E. 1970. Casing Damage Caused by Jet Perforating. Presented at the Fall Meeting of the Society of Petroleum Engineers of AIME, Houston, Texas, 4-7 October.
  19. Bell, W.T. and Shore, J.B. 1981. Casing Damage from Gun Perforators. Paper presented at the 1981 IADC Explosive Conference, 9–11 June.
  20. Bell, W.T. and Bell, R.M. 1981. The Paradox of Gun Power vs. Completion Efficiency. Paper presented at the 1981 IADC Explosive Conference, 9–11 June.
  21. King, G.E. 1989. The Effect of High-Density Perforating on the Mechanical Crush Resistance of Casing. Presented at the SPE Production Operations Symposium, Oklahoma City, Oklahoma, 13-14 March 1989. SPE-18843-MS.
  22. King, G.E. 1990. Casing Crush Resistance Loss to High-Density Perforating: Casing Tests. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 23-26 September 1990. SPE-20634-MS.
  23. 23.0 23.1 Godfrey, W.K. 1968. Effect of Jet Perforating on Bond Strength of Cement. J Pet Technol 20 (11): 1301-1314. SPE-2300-PA.
  24. Crump, J.B. and Sabins, F.L. 1989. Guidelines for Selecting Cement that will be Perforated. Southwestern Petroleum Short Course, Lubbock, Texas, April 1989.
  25. Brinsden, M., Boock, A., and Baumann, C. 2014. Perforating Gunshock Loads: Simulation Capabilities and Applications. Presented at the International Petroleum Technology Conference, Kuala Lumpur, Malaysia, 10–12 December. IPTC-17819-MS.
  26. Baumann, C. and Brinsden, M. 2014. Perforating Gunshock Loads: Simulation and Optimization in 2014. Presented at the IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition, Bangkok, Thailand, 25–27 August. SPE-170552-MS.
  27. Baumann, C.E., Bustillos, E.P., Guerra, J.P., William, A., and Williams, H.A.R. 2012. Reduction of Perforating Gunshock Loads. SPE Drill & Compl 27 (1): 65–74. SPE-143816-PA.
  28. Baumann, C., Benavidez, M., Martin, A., Salsman, A. and Williams, H., 2012. Perforating on Wireline - Weak-Point Load Prediction. Presented at the SPE/EAGE Unconventional Resources Conference and Exhibition, Vienna, Austria, 20–22 March. SPE-152431-MS.
  29. Baumann, C., Dutertre, A., Khaira, K., Williams, H., Mohamed, H.N.H. 2012. Risk Minimization when Perforating with Automatic Gun Release Systems. Presented at the SPETT 2012 Energy Conference and Exhibition, Port of Spain, Trinidad, 11–13 June, SPE 156967-MS.
  30. Baumann, C., Lazaro, A., Valdivia, P., Williams, H., Stecchini, P. 2013. Perforating Gunshock Loads—Prediction and Mitigation. Presented at the SPE/IADC Drilling Conference and Exhibition, Amsterdam, The Netherlands, 5–7 March. SPE-163549-MS.
  31. Regalbuto, J.D., Leidel, D.J., and Sumner, D.R. 1983. Perforator Performance in High Strength Casing and Multiple Strings of Casing. Paper presented at the 1983 API Pacific Coast Meeting, Bakersfield, California, 8–10 November.
  32. King, G.E. 1989. Perforating Multiple Strings of Casing: Getting Through the Overlap Zone. Southwestern Petroleum Short Course, Lubbock, Texas, April 1989.
  33. Baumann, C., Williams, H., Korf, T., and Pourciau, R. 2011. Perforating High-Pressure Deepwater Wells in the Gulf of Mexico. Presented at the 2011 SPE Annual Technical Conference and Exhibition, Denver, USA, 30 October–2 November. SPE-146809-MS.

Noteworthy papers in OnePetro

Behrmann, L.A. and Nolte, K.G. 1999. Perforating Requirements for Fracture Stimulations. SPE Drill & Compl 14 (4): 228–234. SPE-59480-PA.

Snider, P.M., Benzel, W.M., Barker, J.M. et al. 1997. Perforation Damage Studies in Unconsolidated Sands: Changes in Formation Particle Sizes and the Distribution as a Function of Shaped Charge Design. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 5-8 October 1997. SPE-38635-MS.

Venkitaraman, A., Behrmann, L.A., and Chow, C.V. 2000. Perforating Requirements for Sand Control. Presented at the SPE European Petroleum Conference, Paris, France, 24–25 October. SPE-65187-MS.

External links

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See also


Perforating methods

Perforating equipment

Pipe cutoff methods