Production Report

Matrix treatment arrests production decline in deepwater GOM well

Case history and lab tests of successful salt block inhibitor that prevents serious wellbore scale deposits

 Syed A. Ali, ChevronTexaco, and Leonard J. Kalfayan, BJ Services

 The first matrix squeeze treatment using the novel Saltrol 2 Salt Block Inhibitor from BJ Services was successfully applied in a ChevronTexaco well, in the deepwater Gulf of Mexico. Elsewhere, Saltrol 2 had previously been applied successfully in conjunction with fracturing stimulation. Results of the unprecedented offshore matrix treatment are summarized below. Preceding the treatment case example is a summary of lab core-flow test data showing effectiveness of Saltrol 2 in matrix treatment application to temperatures as high as 350°F.

  INTRODUCTION

 Deposition of sodium chloride (halite) in well systems is a significant problem in different areas of the world that can result in significant production deferment and necessitate costly well intervention. Salt scaling is particularly severe in wells producing highly saline (>200,000 mg/l) formation brines, or brines near saturation with respect to sodium chloride. In such cases, the potential for generating large quantities of halite scale exists as produced fluids rise in the wellbore and cool – precipitating salt from solution and forming salt bridges in the flow system. Like any scale deposit, these halite deposits can bridge in the tubing and restrict production capacity of the well or surface flowline, Fig. 1. 

Fig. 1. Salt deposition in the wellbore.

 The precipitation of salt downhole results in substantial well-productivity decline, and may culminate in total flow blockage. Relatively low produced-water rates per day can still result in rapid salt deposit buildup and dramatic oil or gas production reduction. For example, a well with a downhole temperature of 212°F, a wellhead temperature of 90°F, and producing sodium chloride brine at or near salt saturation, will precipitate about 10 lb of salt per barrel water produced. Although halite deposits are generally easier to remove than other scales – most commonly by periodic washing with fresh or low-salinity water – the often rapid buildup rate requires frequent well intervention to maintain well productivity. 

 Preventing halite scale buildup has been accomplished only through continuous dilution of the producing fluid stream with low-salinity water, upstream of the point where deposition occurs. This has been the only practical treatment due to the apparent absence of a suitable halite scale inhibitor. 

 For removal, water washes are routine; however, they often require significant volumes of low-salinity water, which may not always be readily available. Further, transporting fresh water can be costly, especially if repeated frequently. Production downtime and additional post-treatment lifting expenses associated with fresh or low-salinity water wash treatments to remove salt deposits can also be significant – especially in offshore environments. 

 To address these problems and limitations associated with salt-block formation and removal, and to fill the gap in salt-block preventive technology for matrix treatments, ChevronTexaco initiated a project with BJ Services to evaluate a new salt-block inhibitor squeeze treatment system. 

  LABORATORY EVALUATION

 Table 1 summarizes results of lab core-flow testing showing the effectiveness of Saltrol 2 salt block inhibition at temperatures up to 350°F. 

 Test results show that prior to the new treatment, it was possible to damage permeability to brine through injection of saturated NaCl solution. However, after Saltrol 2 treatment – in each test temperature case – the core could not be re-damaged with saturated NaCl solution, indicating prevention of salt block formation. Permeability to oil was not affected by the new treatment.

 Each core-flow test utilized a cylindrical core about 1 in. by 3 in., seated in a rubber sleeve and mounted in a Hassler-type core-flow system. Plugs were subjected to 1,500-psi confining pressure and saturated with filtered 2% ammonium chloride (NH₄Cl) solution. The system was gradually heated to 200, 250, 300 or 350°F, depending on the desired test temperature. Back pressure of 300 psi was applied throughout all flow tests, while maintaining the 1,500-psi confining pressure. In each test, the following fluid permeability measurements were made:

     Before treatment 

1.  Permeability to saturated NaCl solution (<24 hr)
2.  Permeability to standard mineral oil at irreducible brine saturation in the core (<24 hr)
3.  Permeability to saturated NaCl solution – until damage from salt deposition occurred (12 – 60 hr).

     After treatment

1.  Permeability to saturated NaCl solution – after removal of salt block formed in Step 3 above (<24 hr)
2.  Permeability to standard mineral oil at irreducible brine saturation (<24 hr)
3.  Permeability to saturated NaCl solution – attempt to re-deposit salt following Saltrol 2 treatment (up to 60 hr). 

     Treatment procedure

1.  Pre-pad (2% KCl + 0.6% water-wetting surfactant): three pore volumes
2.  Inhibitor pad (2% KCl containing Saltrol 2 concentrate): three pore volumes
3.  Spacer (2% KCl): 10 pore volumes
4.  Inhibitor pad (2% KCl containing Saltrol 2 concentrate): three pore volumes
5.  Post-pad (2% KCl + 0.6% water-wetting surfactant): three pore volumes. 

 A concentrate of 20% Saltrol 2 in 2% KCl solution was used for tests run at 160, 200, 250 and 300°F. A concentrate of 30% Saltrol 2 in 2% KCl solution was used in the 350°F test. 

  MATRIX SQUEEZE TREATMENT APPLICATION

 To summarize the problem, wells drilled and completed subsea frequently present challenges not encountered on land locations. The ChevronTexaco Well A-2 drilled off the shelf in the Gulf of Mexico provides an example. Although the well was capable of producing a high volume of oil and only a very small amount of water (12,000 bopd and 20 bwpd), salt problems started with the very early production. 

 Salt blocks would restrict production to less than 50% of expected volumes, and then the well would require fresh water washing to restore productivity. Washing would normally restore production rates, but bottomhole flowing pressure would drop significantly (200+ psi) within 3 – 5 days. Within 30 days, production would again be restricted and another cleaning would be required. The washing cycle became a normal routine, with associated loss of production, downtime and expensive cleaning. 

    The solution. Following a thorough cleaning through tubing with KCl brine, the well was squeezed with Saltrol 2 inhibitor. Existing salt was removed by pumping 600 bbl of 7% KCl solution in five stages, separated by foam diverter. Following salt removal treatment, the well was produced long enough to unload the wash fluid. Table 2 summarizes the inhibitor squeeze treatment. 

 Salt inhibitor treatment was preceded by a spearhead of 7% KCl solution containing a surfactant to condition the reservoir for inhibitor adsorption. Treatment of the 74-ft perforated zone was designed in three stages, separated by foam diversion. 

 Each stage injected a Saltrol 2 Salt Inhibitor treatment phase, followed by a segment of 7% KCl brine large enough to push the inhibitor into the formation out to a 4-ft radius. After the last stage, the treatment was displaced out of the wellbore and into the reservoir. The well was shut in overnight to allow the inhibitor to glaze onto the reservoir rock. The well was then returned to production. 

  PERFORMANCE BENEFIT

 The well responded by quickly establishing production in excess of 10,000 bopd. This rate continued for nearly two months with little or no indication of salt deposition. Production followed normal decline rate – without the sharp decline indicative of salt buildup. Bottomhole flowing pressure was maintained during this time, unprecedented in the history of the well. Since the periodic drop in productivity due to growing salt deposits was not observed, a significant reduction in operating expense was realized, as cleaning operations and associated downtime were eliminated. 

 The greatest benefit from treatment was the increase in total oil production. By eliminating the productivity downturn, produced oil accumulated at a high production rate, adding many barrels with minimal additional lifting cost. After 54 days of production, fresher aquifer-water breakthrough to the wellbore occurred. Thus, the well was no longer a potential salt producer; and the treatment evaluation period (successful to that point) ended. The production plot in Fig. 2 shows well performance before and after the Saltrol 2 Salt Block Inhibitor squeeze treatment. 

Fig. 2. Well A-2 performance before and after Saltrol 2 inhibitor squeeze treatment.

 Comparing oil production during the 54-day period following the previous salt removal treatment (water-wash only) and during the 54-day period following Saltrol 2 matrix treatment shows the significant improvement in productivity. During the previous 54 days, oil production was 287,407 bbl, averaging 5,422 bopd. For the same period after the squeeze, the total was 534,141 bbl, averaging 9,891 bopd. At $20/bbl, revenue generated from the accelerated incremental oil production was about $4.9 million; and the combined salt removal/ salt inhibition treatment paid out in less than three days.  

 BIBLIOGRAPHY

 DeVine, C., BJ Services Technology Center Report 03-04-0415, “Saltrol 2 product testing of core plugs from a Green Canyon well, offshore Louisiana.”

 Frigo, D. M., et al., “Chemical inhibition of halite scaling in topsides equipment,” paper SPE 60191, presented at the 2000 International Symposium on Oilfield Scale, Aberdeen, UK, January 26 – 27, 2000.

 Kirk, J. W. and J. B. Dobbs, “A protocol to inhibit the formation of natrium chloride salt blocks,” paper SPE 74662, presented at the 2002 Oilfield Scale Symposium, Aberdeen, UK, January 30 – 31, 2002.

 Kleinitz, W., M. Koehler and G. Dietzsch, “The precipitation of salt in gas producing wells,” paper SPE 68953, presented at the SPE International Formation Damage Symposium, The Hague, the Netherlands, May 21 – 22, 2001.

 Place, M. C. and J. T. Smith, “An unusual case of salt plugging in a high-pressure sour gas well,” paper SPE 13246, presented at the 59th Annual Technical Conference and Exhibition, Houston, September 16 – 19, 1984.

THE AUTHORS
	Syed A. Ali, a Research Consultant for ChevronTexaco E&P Technology Co. in Houston, holds an MS degree from Ohio State University and a PhD from Rensselaer Polytechnic Institute. He specializes in sandstone acidizing, formation damage control, rock-fluid interaction, mineralogy and oilfield chemistry. He has 27 years’ experience in the oil/gas industry.
	Leonard Kalfayan, BJ Services’ Product Line Technology Manager for Acidizing & Matrix Applications, has 23 years’ petroleum industry experience. His primary areas of expertise are in chemical well treatment technologies and applications, supporting the development of acid and matrix stimulation and water management solutions and businesses worldwide. Prior to joining BJ in 1998, he served three years as a consultant. His first 15 years in the industry were with Unocal, specializing in geothermal and heavy oil steam stimulation, acidizing and formation damage. With a BA degree in chemistry from Occidental College and an MS degree in chemical engineering from Purdue University, Mr. Kalfayan is the author of the book Production Enhancement with Acid Stimulation (PennWell 2000), as well as several technical papers, and 11 US patents in steam/ acid stimulation methods and formation damage control.