A survey of a number of U.S. operating companies indicated that their paraffin and asphaltene control programs were poor to excellent.
The Permian Basin Operators` work group developed the survey. Group members include ARCO Permian, Exxon Co. USA Production, PennzEnergy Inc., Artificial Lift Solutions, Occidental Petroleum Corp., Cross Timbers Oil Co., Burlington Resources Inc., Amerada Hess Corp., Texaco E&P Inc., Pioneer Natural Resources USA Inc., Phillips Petroleum Co., and Chevron USA Inc.
The group received 43 completed surveys from the following 12 companies: Amerada Hess, Phillips, Spirit Energy 76, Marathon Oil Co., PennzEnergy, ARCO Permian, Occidental Petroleum, Altura Energy, Burlington Resources, Texaco, Exxon, and Chevron.
The data were from 23 counties in three states: Texas, New Mexico, and North Dakota.
The self-rated effectiveness of each company`s control program was as follows:
- Poor-14.0%
- Fair-32.6%
- Good-48.8%
- Excellent-4.6%
Paraffin precipitation
If oil temperature falls below the cloud point, wax crystals will precipitate from the oil phase. Accumulation of these precipitated solids can impact surface and subsurface equipment operations.
Paraffin precipitation usually is associated with changes in physical conditions surrounding the crude, primarily temperature or pressure. As crude is produced up the well bore, its temperature may decease due to the normal subsurface thermal gradient. Sudden pressure drops, such as through perforations, across chokes, etc., also have a cooling effect on liquids and can promote precipitation.
The reduction in hydrostatic pressure on crude as it is produced up the tubing allows gas to break out of solution. The gas bubbles that form, as pressure is lowered, are the light ends that were in the liquid phase. These light ends helped keep the heavy-end paraffins in solution, thus precipitation can also be caused by this loss of light ends from the liquid phase.
The cloud point is dependent on oil composition and is significantly affected by small amounts of high molecular weight paraffin in the crude.
Asphaltene deposition
Asphaltene deposition is less driven by temperature and pressure. The deposition is affected more by chemical changes in the crude.
Asphaltene molecules are not dissolved in the crude, but are dispersed, or "floating" in it. Lowering the pH of the system (making it more acidic) or introducing carbon dioxide (CO2), or nonaromatic solvents can strip away the asphaltene molecule`s outer part that helps keep the asphaltene molecules dispersed.
Without the outer part, the molecules will flocculate and precipitate.
Poor effectiveness
The operators indicating "poor" program effectiveness did not report testing their crude oil as a part of establishing their control program.
Tests for determining API gravity, cloud point, wax melting point, paraffin and/or asphaltene content, and carbon chain composition or make-up are extremely critical for designing a good control strategy. From these test results, one can tailor a control program to satisfy specific needs of a well.
The majority of poor programs did not incorporate a scheduled treating frequency. If a schedule was followed, the time intervals between treatments seemed excessive.
Because hot oiling and hot watering jobs are commonplace in the industry, it may often be taken for granted that the work is being performed as instructed in a desirable, effective manner. Continued ineffective or undesirable results, however, can indicate poor planning or job execution.
The hot fluid can be either lease crude or produced water. But regardless of the fluid, chemicals were added to assist the process. In the poorly effective treatments, however, the compatibility of the produced fluid, heated fluid, and chemical were not checked.
On two occasions, following treatments, emulsions were noted in produced fluids. Some crude oils could be sensitive to specific compounds that could create emulsions or the produced water could be high in total dissolved solids (TDS).
Compatibility testing may head off these problems.
The typical volume of heated fluid pumped into the well bore was 70 bbl. Fluids were heated to between 150 and 200° F. and pumped at 1 bbl/min. During the normal hot oiling or hot watering process, in the poor programs, the heated fluid was pumped into the annulus faster (about 70 bbl at 1 bbl/min) than a beam pump could produce it back. This fact leads us to believe that large amounts of fluid may have been lost to the formation, especially in low bottom-hole pressure, higher permeability wells.
As this fluid begins to cool, it can accelerate plugging of the reservoir. Plugging agents often found in this fluid may include iron sulfide, iron oxide, clay, scale, paraffin, or asphaltene.
If lease crude is the treating fluid, the potential detrimental effects could possibly be reduced by:
- Using the cleanest oil possible with the least amount of bs&w content.
- Using oil from the top of tanks and not from the bottom. Bottom oil is generally laden with higher bs&w contents.
- Adding chemicals to assist in holding the paraffin particles in solution.
The poorly effective programs did include supplemental chemical treatment programs with either an aromatic or proprietary blend. These supplemental programs were noted as one of the best practices for the poor programs.
The poor programs did not employ scrapers, guides, or coatings for paraffin control.
Fair effectiveness
Paraffin deposition in wells having a "fair" program was at a depth of about 3,000 ft or less, with the majority being between the surface and 2,000 ft.
Again, testing the crude oil has the potential for improving the effectiveness of these programs. Across the industry, regardless of program effectiveness ranking, more testing has the potential for improving the treatments.
The fair programs generally had a scheduled treating program that varied between 30 and 90 days, depending on the specific needs of each location.
The majority of these treating programs used either lease crude or produced water, containing a chemical additive. The most significant success factor appeared to be focused, not only on the chemical additives, but also on checking the compatibility of the heated fluid, produced fluid, and chemical.
The heated-fluid volume per treatment was overwhelmingly 70 bbl, pumped at a rate of about 2 bbl/min and heated to between 150 and 200° F. The improved effectiveness of the fair programs over the poor programs may be due to higher pump-in rates of about 2 bbl/min instead of the 1 bbl/min common in poorer programs. This is consistent with estimates made by Sandia National Laboratories, Albuquerque, N.M.
A.J. (Chip) Mansure, Sandia Labs, developed a computer program to predict tubing and tubing-casing annulus fluid temperature during hot oiling or hot watering jobs. Fig. 1 shows some of the predictive plots. This subsurface heat transfer program has been enhanced and is now distributed by Baker Petrolite.
These data indicate that the same downhole temperature can be achieved at almost twice the depth by increasing the pump-in rate to 2 bbl/min from 1 bbl/min. In a similar manner, Fig. 2 shows the positive effect of increasing the initial temperature of the fluid being pumped in.
In some of the fair programs, hot oil and hot water treatments were supplemented with various chemical programs using condensate, aromatics, or proprietary blends. These treatments are possibly allowing the time interval between hot oiling and hot watering jobs to be greater.
Rod guides or scrapers were not used widely. In some cases several operators are evaluating various configurations of these devices, run between the surface and 4,500 ft.
No operator, in this group, reported using coatings for paraffin control.
Operators with fair programs noted that the program effectiveness was developed through trial and error. Furthermore, comments indicate a clear opportunity and desire to more-efficiently control asphaltene deposition.
They also noted that more science needs to be applied to hot oil/hot water treatments to improve results. Up-front planning could reduce operating expense, thus increasing profitability.
Good effectiveness
The surveys listing programs with "good" effectiveness employed more up-front testing and planning. Almost 49% of the operators indicated that their programs had good effectiveness, but there still appears to be an opportunity for more tests on the crude oil prior to implementing a paraffin control program.
Paraffin deposition ranged from surface to 3,000 ft with the majority of the deposition noted from 2,001 to 3,000 ft.
For the programs with good effectiveness, operators adhered to definite scheduled treatments. Most treatments were scheduled at 30 and 60-day intervals. These programs used lease crude, enhanced with chemicals.
Operators also verified the compatibility of the produced fluid, heated fluid, and chemical. This chemically enhanced fluid, about 70 bbl, was heated to 150-200° F. and pumped at a rate of about 2 bbl/min.
These programs also included chemical treatments, but not on a widespread basis. Only 52% of these programs supplemented the hot oiling with aromatics or a proprietary blend treatment.
Widespread use of scrapers or guides was not reported. Those being used are strictly in a test environment, with the devices being placed in various configurations, ranging from:
- Surface to the seating nipple
- Seating nipple to 1,000 ft above it
- Surface down to 3,000 ft.
There did not appear to be an exact science for deploying these devices.
These programs were developed through trial and error. Many operators indicated that without a planned scientific approach, "the human factor" becomes a large contributor to the success of any program.
Excellent effectiveness
Only 4.6% of the operators rated their paraffin-control programs as excellent. In all of these "excellent" programs, the operator tested the heated fluid, produced fluid, and the chemical for compatibility. The paraffin deposition ranged from the surface to 2,000 ft.
All of the operators indicated that they followed a rigid treating schedule of monthly hot oiling/hot watering wells with either lease crude or produced water.
With both fluids, chemicals were added to the heated fluid for which the compatibility had been checked. Each treatment involved 70 bbl pumped at 1 bbl/min and heated to 150-200° F.
Programs with excellent effectiveness were not supplemented with additional treating programs. Also, scrapers, guides, or coatings were not used.
Observations
Based on this survey, it appears that operators do not perform much up-front planning or testing prior to initiating paraffin-control programs. More up-front planning could reduce the costs associated with learning and refining programs by trial and error. This would enhance profitability.
This up-front planning should consist of:
- Testing the crude for API gravity, cloud point, wax melting point, paraffin/asphaltene content, and carbon chain composition.
- Assuring compatibility of the heated fluid, the produced fluid, and any chemical solvent/dispersant.
Emulsions were noted in the programs where fluid compatibility was not checked. Adding a solvent/dispersant would assist in holding the dissolved particles in solution.
The most common volume pumped in was 70 bbl at a rate of 1-2 bbl/min.
When pumping heated fluids, crude, or water, the following should be considered:
- Heat fluids to as high an initial temperature as safely possible without exceeding the short-term temperature exposure rating for any limiting equipment, such as fiber glass rods, fiber glass or polyethylene tubing, or flow lines, etc.
- Pump fluids as fast as possible without exceeding production facility limits.
The data indicate that an acceptable paraffin-control program is difficult to obtain without a chemical-inhibition program. Also, use of rod guides, scrapers, or coatings for paraffin control is not widespread in the industry.
Acknowledgments
The authors express appreciation to Burlington Resources and Chevron USA Production for allowing this article to be published. They also thank the Permian Basin Operators` work group, operators who responded, and Nancy Hinkle who compiled the data, for their help with this survey.
The Authors
Karl Ivanhoe is currently an operations supervisor for Chevron in West Texas. In his 19 years with Chevron, he has worked in operations and been involved with chemicals, corrosion, and artificial lift.
Ivanhoe holds an associates degree in applied science in petroleum engineering technology from Odessa College.
James Herman is a senior staff production engineer for Burlington Resources in Midland, Tex. His 29 years experience in the industry include various drilling, reservoir, and production-engineering assignments with Texaco Inc. and Union Texas Petroleum prior to joining Burlington in 1991. Herman holds a BS in petroleum engineering from Texas Tech University.