What’s New in Production

New technique eliminates high-density completion fluids

Technique simplifies completion fluid use, reduces need for drilling or workover rig and can be adapted to monobore wells

Charles Ebinger, Completion Engineers, Lafayette, Louisiana

 Several oil and gas companies operating in the Gulf of Mexico are using a new, patented completion technique which eliminates the need for high-density completion fluids. Concerns about the loss of productivity sustained with losses of high-density brines have been substantiated in recent technical presentations.^1,2 The high cost of these fluids, coupled with formation damage, led to development of the new technique. The procedure is applicable for deepwater-well completions by eliminating the need for high-density completion fluids. 

 The technique also reduces, or eliminates, need for a drilling or workover rig during completion.³ Actual cost savings are included in this article. Most of the wells in the case histories are located in the Gulf of Mexico, where cost reductions have been significant. Most of the wells were frac packed, which has become the primary completion procedure along the Gulf Coast, where production of formation sand is a consideration.⁴ Two of the wells are producing over 20 MMcfd. 

This article also covers cost reductions in performing recompletions in zones above the lowest, primary completion, Fig. 1. These upper completions can be done without need for a workover / completion rig.⁵ In the cases where relatively small reserves would not be economically feasible to complete, the new technique allows the operator to produce these smaller zones. 

Fig. 1. Rigless recompletion of future zone.

 An adaptation of this technique using monobores in the Gulf of Mexico is addressed.⁶ Monobores, or tubingless completions have been used extensively in producing fields worldwide. Formations that require some type of sand control have limited the application of monobore drilling and completions. The new technique will allow the operator to realize considerable savings in both drilling and completion costs. 

 The basic concept described here can also be used in “screenless” completions to eliminate need for high-density completion fluids. Screenless completions have become more common in areas where producing-sand permeability is less, and sanding tendencies are reduced.⁷ The zones are hydraulically fractured with propped fracture lengths commonly used in low-permeability zones worldwide. 

 Basic Procedure

 The technique uses tools, services and products that are commonplace in completions routinely performed in producing areas where sand control is required. Thru-tubing products and services are available throughout the world. A basic procedure is listed, as follows: 

1. After casing string is set and cemented, a bond log is run.
2. A cast-iron bridge plug is set at a pre-determined depth, below the lowest zone, Fig. 2.
3. Drilling fluid is displaced with an 8.5-ppg KCl completion fluid, Fig. 3.
4. A production packer is set 100 ft above the uppermost zone. This packer should be able to withstand pressures encountered during the frac procedure.
5. Production tubing, with subsurface safety valves (SCSSVs) is run, and set into the packer.
6. The tree is installed and tested.
7. The rig can now be removed. Remaining completion work is done with a lift boat, or off a platform deck.
8. Calculations are made to determine pressure to place on the well to allow for difference in reservoir pressure and hydrostatic pressure of the KCl fluid, in order to perforate the zone balanced, or slightly over-balanced.
9. If zone is to be frac packed, a thru-tubing gun is used to perforate, with 6 spf, Fig. 4.
10. Subsurface safety valves are used to maintain required pressure on the zone to prevent influx of formation sand after removing perforating guns.
11. Dual-screen / vent screen BHA is made up, run in the hole and placed on top of the cast-iron bridge plug. This assembly can be run on E-line, braided line or coiled tubing. Various types of disconnect devices are used to deploy the BHA, Fig. 5.
12. A wellhead isolation tool is installed on the tree. Then a calculated pressure is placed on the annulus to minimize tubing movement during frac pack operation.
13. The zone is frac packed, or gravel packed, with a KCl displacing fluid, Fig. 6.
14. Normally, the zone is flowed back into a test tank with a gas buster.
15. When tubing volume and casing volume below packer to top of the vent screen is recovered, there should not be any noticeable proppant. 
16. Well is now ready to flow into surface production facilities, Fig. 7.

Fig. 2. Cast iron bridge plug at pre-determined depth

Fig. 3. Displacing drilling fluid with KCl water.

Fig. 4. Thru-tubing perforating with surface controlled subsurface safety valves.

Fig. 5. Deployment of dual-screen / vent BHA.

Fig. 6. Frac pack treatment.

Fig. 7. Flow back after frac pack

 Some companies have attempted to place a cement or mechanical device on top of the annular pack to prevent pack evacuation while producing. The procedure in this article has been performed on more than 100 zones without flowing annular pack material out of the well. It does require careful planning and execution to insure that this does not occur. 

 The dual-screen / vent screen assembly is a closed cylinder, placed in the well by various methods, Fig. 8. Flow from the formation passes through the annular pack, into the production screen, up the inside of the cylinder, out through the vent screen and up the tubulars to surface. Flow through the annular pack in the production screen and blank is restricted by Darcy’s Law. 

Fig. 8. Schematic of dual-screen / vent assembly.

 Primarily, the amount of blank above the production screen should be a minimum of 90 ft. In addition, a series of re-stress injections at 1 bpm is suggested, with a 15-20-min. waiting period between re-stresses. The pressure slope increase will become more rapid on each subsequent re-stress and, when this occurs rapidly, it is surmised that the pack has been tightly accomplished. When a cross-linked polymer fracturing fluid is used to place the frac pack, the cross-link addition is stopped in the last treatment stage. This is done to help obtain a tighter pack in the linear gel carrying fluid. 

 Completion Fluids

 Various types of solids-free completion fluids have been utilized for years in oil / gas-well completion procedures. Normally, the mud used during drilling operations is changed out with these completion fluids after casing has been run and cemented. Use of these solids-free fluids has improved well productivity substantially. Fluid types have included potassium chloride, sodium chloride, calcium chloride, calcium bromide and zinc bromide, as well as some new solids-free fluids. Fluid type and density are determined by bottomhole pressure of the zone to be completed. Cost of these fluids increases as density increases. 

 Companies that furnish these various fluids will sell the higher density fluids with a buy-back arrangement and reconditioning charge. Unit cost of zinc bromide in the higher density range is over $500 / bbl; and when losses to the formation occur, the resultant completion cost is high. Various types of fluid-loss systems have been used to reduce these losses, but they can also add to the reduction in well productivity and cost. HEC, cross-linked HEC, graded salt and carbonate pills are commonly used. 

 The productivity of some formations can also be reduced by incompatibility of completion fluids with reservoir fluids and formations. This problem is more severe in the higher density completion fluids. Recent studies show effects of emulsions, scale and hydrates caused by these fluids in many cases. Eliminating these high-density fluids in well completions can dramatically reduce completion costs. The well-productivity issue, due to incompatibility, may be more important than the tangible cost savings.

 Case Histories

 A diverse group of wells and projects are summarized here. Although basic procedures were similar on all wells, there were differences in the type of wells and overall completions. All wells in this article are natural gas producers, but the technique can be used on oil-producing zones as well. Most of the wells were located offshore in the Gulf of Mexico, but the “rig-less” dual-screen technique has been used on a number of wells on land and inland waters. 

 Project A. These two wells were drilled in the Ship Shoal area, and temporarily suspended. A rig was moved back onto the project to tie back the liners and complete the primary zones. Due to the water depth of 264 ft, a lift boat could not be used for the completions. The zones on both wells would normally have required zinc bromide as a completion fluid, but the operator was concerned about productivity impairment and cost.

 Both wells were completed using the procedure described in this article, with 3 1/2-in. tubing for the high production rates anticipated. The wells were frac packed, and both produced at rates over 20 MMcfd. Cost savings, primarily due to eliminating zinc bromide, were estimated at over $300,000 per well. If water depth had been less, a large lift boat would have replaced the drilling rig after tubing was run and the tree installed. 

 One of the wells has an upper zone that will be completed after the primary zone is depleted. The upper zone is below the production packer, and the recompletion can be performed by setting a thru-tubing bridge plug with cement on top. This zone will then be frac packed and produced. 

 Project B. This well was drilled in the Ship Shoal area, and the rig completed necessary work for the dual-vent / screen completion. The operator wanted to eliminate calcium bromide as a completion fluid, and the drilling rig. With water depth greater than 200 ft, the platform was used for all work. Due to a 60 wellbore deviation, a coiled tubing unit was utilized to deploy the dual-screen assembly. The completion was performed without problems, and the zone was flowed back without having to wash out to the top of the vent screen with coiled tubing, Fig. 9. 

Fig. 9. Case B well completion schematic.

 The well is producing at 7 MMcfd, with a surface drawdown of 200 psi. The flowing rate is presently restricted due to pipeline pressure limitations. This well was completed for $190,000 less than the offset well that was done conventionally. An additional $110,000 was saved by eliminating calcium bromide, for a total savings of $300,000. The operator on Project B has a number of wells offshore and in inland waters that may be completed with this technique. 

 Project C. This oil and gas company purchased a field from another operator in the Gulf of Mexico and has been involved in a long-term field development drilling program to recover remaining reserves. Most of these wells have multiple zones and, with a thoroughly planned program, the company will do a series of completions and recompletions. Initial completions on some of these wells were done conventionally, with the production packer set high enough to allow thru-tubing recompletions on all zones above the primary zone, Fig. 10. 

Fig. 10. Case C well completion schematic.

 A high-rate water pack (HRWP) was performed on the E-8 sand using the dual-screen / vent assembly technique. After three months, this well was successfully producing over 8 MMcfd and 250 bopd. 

 Water depth in this project is shallow enough to use a lift boat in all recompletions. Reserves in some of the zones are relatively small and will be depleted in less than one year. The first recompletions have been performed successfully, and new zones are producing at acceptable rates. 

 Project D. This operator has had a long-term development-drilling program underway for the past few years. Having recompletion potential in upper zones, it set the wells up for “rig-less,” thru-tubing recompletions. Some of these wells are on platforms in the South Marsh Island area offshore, and the platforms are large enough to perform recompletions without a rig or a lift boat. BHP on the upper zones varies, but by using the technique described herein, they will not have to use higher-density completion fluids on any of the recompletions. 

 Monobores

 Monobores, or tubing-less completions, have been used worldwide for many years to reduce drilling, tubular and completion costs. Numerous case-history studies have documented the savings from using this technique. Fields that require low-cost development, due to small reserves, may not be economical to drill with conventional methods. 

 Typically, a monobore well has a smaller-sized production casing string, and does not have tubing. Sizes of monobores have been from 2 7/8 to 5.0-in. casing, depending on a number of factors – the primary design criteria being probable well-productivity rates. 

 In the past, this method has not been used in producing areas where formation sand control is required. The advances in thru-tubing completion technology, and wide use of dual-screen / vent screens, where sand control is necessary, have made this technique possible. One of the major obstacles to overcome was well control during completion. In the Gulf of Mexico, governmental approval was required to utilize this type of drilling / completion procedure. 

 Well control during completion is done by using one or two subsurface safety valves to maintain pressure on the formation after perforating in an under-balanced-fluid scenario. The SSSVs are functioned to allow the dual-screen / vent BHA to be deployed, and still keep a combination of fluid hydrostatic and wellhead pressure on the formation.

 Recompletions of zones up the hole are done with a considerable cost savings. No rig of any type is required to perform the new-zone completion, as it is done with wireline equipment to perforate and deploy the dual-screen / vent assembly. A thru-tubing bridge plug is set at a predetermined depth, and cement is dump bailed on top to insure that it does not move downhole. The rest of the completion is performed in the same manner as the lower zone. 

 If the possibility of corrosive producing fluids exists, chrome casing and internal completion assemblies may be required. If small diameter casing, such as 3-1/2 -in, is run, it will not significantly add to overall well cost. 

 Conclusions

 Results on a number of wells have shown that this new technique can reduce the cost of well completions. Eliminating high-density completion fluids reduces productivity impairment and lowers overall completion costs. And well costs can also be reduced by not having a rig on the well during all, or part of the completion. 

 High producing rate wells are possible with dual-screen frac packs. The technique can be used on offshore wells, deepwater wells, inland water and land wells. And monobore-type wells are ideal applications for the technique. New advances in technology will extend use of the procedure. 

Acknowledgment

 The author would like to acknowledge the following people for assistance and information in the preparation of this article: Wayne Ducote with Completion Engineers, for his field implementation and wellbore schematics; Jay C. Cooke with the estate of William G. Helis, LLC; Jim Docherty with PetroQuest Energy; Bill Folsom with Taylor Energy; Tom Lincoln, consultant with McMoran Oil & Gas; Norman Fakier with Petsec Energy; and Joe Serio with BJ / OSCA. 

Literature Cited

  ¹ Luyster, M. R., et al., “Asphaltenic crudes and high density brines: A potentially lethal problem,” paper SPE 73732, presented at the Formation Damage Control Symposium, Lafayette, La., February 2002. 

  ² Ali, S. A., et al., “Formation damage traced to contaminated completion fluid,” Oil and Gas Journal, Aug. 12, 2002, pp. 45 – 51. 

  ³ Ebinger, C.D., “Rigless frac packs provide cost-effective completions,” World Oil, October 2000, pp. 68 – 76.

  ⁴ Ebinger, C.D., “Frac pack technology still evolving,” Oil and Gas Journal, Oct. 23, 1995, pp. 60 – 70.

  ⁵ Ebinger, C.D., “New frac-pack procedures reduce completion costs,” World Oil, April 1996, pp. 71 – 75. 

  ⁶ Sanford, J. R., et al., “Utilizing 4 _-in. monobores and rigless completions to develop marginal reserves,” paper SPE 54475, presented at the SPE / CoTA Coiled Tubing Roundtable, Houston, Texas, May 1999. 

  ⁷ Riddles, C., et al., “Rigless, screenless completions solve sand control problems in two offshore fields,” Offshore, June 2002, pp. 48 – 98.

The author
	Charles D. Ebinger, is president of Completion Engineers. He is a 1956 graduate of the Colorado School of mines and has spent his 46-year career involved in well completion engineering worldwide. Mr. Ebinger is a registered engineer and a member of SPE, AAPG and API. He has written numerous technical articles and holds various patents in the field of well completions.