UNIFORM PROGRAM REDUCES PARAFFIN REMOVAL COSTS

Gregory A. Hicks
Texaco USA
Midland, Tex.

Initiating a uniform hot-oiling program will help maximize lease profit, minimize paraffin problems, and reduce duplication of work.

Establishing hot-oiling schedules also promotes communication between foremen and field personnel and improves the efficiency of field operations.

AREA STUDIED

Wells completed in the San Andres formation in Hockley and Cochran Counties, Tex., were studied to establish a uniform paraffin-removal program.

Several methods of paraffin removal, including hot oiling, batch treating with chemical, paraffin-inhibitor squeezes, and batch treating with paraffin-eating bacteria, were evaluated.

The north and west sectors of the Levelland area produce from the San Andres formation at an average depth of 5,000 ft. The north sector consists of the following leases: Montgomery Estate Davies, Medarby, I.P. Deloache, Coble A and B, Cunningham, Ham, Thruston, Whirley, and Wrenchy.

The west sector includes the C.S. Dean A, XIT, and Southwest Levelland units.

Within these sectors are leases with Texaco's working interests ranging from 28 to 100%. The two sectors combined produce 5,811 bo/d and 17,099 bw/d from 427 wells.

The combined hot-oiling expense for 1988 was $233,148 or $546/well. For this discussion, hot oiling will be defined as pumping hot water down the casing and hot oil down the flow line.

CRUDE CHARACTERISTICS

The crude is 24-30 API gravity containing 2-18% paraffin and 2-9% asphaltene residue (Table 1). The paraffin is a combination high molecular weight and branched microcrystalline wax as verified by gas chromatography analysis.

The paraffin deposits analyzed contained a wax composed mainly of carbon number 40-50.

The cloud point or temperature at which paraffin begins to precipitate ranged from 24 to 75 F.

The pour points or temperatures at which the crudes will not flow range from -55 to 5 F. The melting points of the crudes range from 160 to 168 F.

METHODS EVALUATED

Several different types of paraffin removal were analyzed to determine the most effective and economical method of removing paraffin. The north and west sectors had paraffin-treating schedules in place at the time of this evaluation.

These schedules were similar in type of fluids pumped but different in method of application. It was necessary to evaluate these different methods to develop a uniform paraffin treatment.

First, different volumes were used on wells in the west sector and the results compared.
Second, each lease's individual paraffin-treating schedule was evaluated.
Third, the recommended paraffin-removal method was initiated on the XIT unit and the results evaluated.
Fourth, different chemicals were tested to determine the type and amount of hot-oiling chemical necessary to maximize paraffin removal.

INITIAL EVALUATION

Annular and flow line volumes were varied for twelve wells on the C.S. Dean A and XIT units and the results recorded. These results are tabulated in Table 2.

Three different types of treatments were analyzed in four well groups. The first included pumping 50 bbl of water down the casing and 10 bo/1,000 ft of flow line.

The second included pumping 75 bbl of water down the casing and 10 bo/1,000 ft of flow line. The third consisted of pumping 75 bbl of water down the casing and 75 bbl of oil down the flow line.

The motor's high and low amperage readings did not show a significant change between the three treatments. Flow line pressures also showed little change between the three. Therefore, it was determined that the first type of treatment would be field tested on the XIT unit.

FIELD TESTS

A field test conducted on the XIT unit, with the recommended paraffin-removal method, consisted of pumping 50 bbl of water mixed with 2.5 gal of a nonionic surfactant down the casing and pumping 10 bbl of oil/1,000 ft of flow line. Wells on this lease were hot oiled based on a schedule set for each individual well by the lease foreman.

The wells were initially setup on a quarterly schedule. As the well was due for scheduled work, the check valves at the wellhead and satellite were visually inspected for paraffin deposition and compared to the wellhead pressure. If the inspection indicated that hot oiling could be postponed, the treatment was delayed until the following month.

The same procedure was repeated until it was deemed necessary to hot oil. This procedure was repeated for each well until an optimum schedule was developed.

Initiation of this paraffin-removal method resulted in an average treating cost of $362/well/year as shown in Table 3. This was the lowest paraffin-treating cost per well in the Levelland area in 1988.

OTHER METHODS

The west sector also utilized another type of paraffin removal on the C.S. Dean A and Southwest Levelland units. These wells were hot oiled with 75 bbl of water down the casing and 75 bbl of oil down the flow line. The water was also mixed with 3 gal of a nonionic surfactant.

These two leases differ from all other leases evaluated in that most of the flow lines are either 2 or 3-in. steel and are on the surface.

The wells drilled after 1976 are the only wells producing through buried fiber glass lines. The steel lines cause problems because of their size and the effects of cold weather.

The Dean A and Southwest Levelland units hot-oiling expenses for 1988 were $41,121 ($534/well) and $21,154 ($587/well), respectively (Table 3). These costs are very low considering the operating conditions.

The north sector utilizes a single method of paraffin removal. The majority of the wells on the lease are hot oiled every quarter with 50 bbl of water down the annulus and 25 bbl of oil down the flow line (Table 2). Each load of fluid is mixed with 5 gal of paraffin dispersant.

Many of the wells are hot oiled with 75 bbl of oil down the flow line in the second and fourth quarters (Table 4 and 5). This prepares the flow lines for winter in the fourth quarter and in the second quarter removes any buildup that occurred during the cold winter months. In the west sector the flow lines are hot oiled as needed (Table 4).

In the north sectors expenditures for hot oiling and hot oiling chemicals are $135,688/year. This equates to a cost of $625/well/year (Table 3).

CHEMICAL EVALUATION

Chemical companies in the Levelland area were requested to evaluate Texaco's paraffin and oil, and then to submit their best product. These chemicals were tested with oil and paraffin from both the north and west sectors.

Emulsion tendencies were also checked between the chemicals and the oils. The procedure for testing the chemicals is shown in Table 6. Based on its ability to keep the cooled paraffin separated, a nonionic surfactant was selected as the chemical to be mixed in the water. A chemical to mix in the water was needed to prevent solids from being pumped into the formation.

A surfactant is a good water-wetting chemical for formations. Many wells will go on a vacuum due to the low bottom hole pressures encountered. A water-wetting chemical will benefit production over the life of the waterflood in this situation.

Also this nonionic surfactant is very good at carrying solids that will aid in removing iron sulfide and other plugging agents from the well bore. The results of this test are shown in Table 7.

Two chemicals were selected to mix with the oil when pumped down the flow lines or tubing. A paraffin solvent was selected for the west sector, while for the north sector the choice was a paraffin dispersant.

During hot oiling, 1 gal of each chemical was determined to be adequate for any amount of oil pumped. The test conducted on 1 gal increments of these chemicals showed little increase in paraffin removal between 1 and 5 gal (Table 8). Using these chemicals will increase paraffin removal and decrease gunbarrel interface problems.

After the chemicals were determined for hot oiling, an emulsion tendency test was run. This consisted of obtaining three 100-cc samples and adding the appropriate amount of each chemical to each sample. The samples consisted of 25%, 50%, and 75% oil. An emulsion was not detected in any of the samples.

OTHER REMOVAL METHODS

Other methods of paraffin removal were either tested or evaluated with little success. For a method to be tested, its treating cost had to be as good as or better than the current treating cost. This eliminated the paraffin-inhibitor squeezes and the paraffin-eating bacteria.

The paraffin-inhibitor squeezes had a recommended cost of $1,500/well and had a forecast squeeze life of 1 year or less. The paraffin-eating bacteria had a recommended cost of $200/well /month or a yearly cost of $2,400.

These costs did not include any trucking or labor costs.

Because paraffin-inhibitor squeezes and paraffin-eating bacteria failed to meet the economic criteria, they were not tested.

Batch treating down the annulus was tested with two different chemicals. Two paraffin dispersants were tested on the XIT and Southwest Levelland units. These chemicals were used in five of the problem wells on each lease.

Treatments consisted of 5 gal of chemical pumped down the annulus of each well, followed with 5 bbl of fresh water. Treatments were scheduled twice monthly at a cost of $30/treatment or $60/month.

Two of the wells on each lease were pulled within 2 months after the project began to visually inspect for paraffin buildup on the rods. Paraffin was found no lower than 1,000 ft on the XIT and no lower than 1,200 ft on the Southwest Levelland.

Paraffin accumulations were slight on the XIT and very heavy on the Southwest Levelland. The treatments on all of these wells were discontinued as they had to be hot oiled within 6 months of project initiation. Forecast cost for this type of treatment was $720/year which is 24% greater than the current average hot-oiling cost.

RECOMMENDATIONS

A uniform paraffin-removal method was developed after all methods had been evaluated. The following hot-oiling procedure was recommended:

Treat each producer with 50 bbl of fresh water down the annulus and 10 bo/1,000 ft of flow line. After the temperature of all fluids is 220 F., 2 gal of a nonionic surfactant will be added to the water while 1 gal of either a paraffin solvent or paraffin dispersant will be added to the oil.
Monitor paraffin accumulation in the check valves at the wellhead and satellites/batteries, and monitor flow line pressures.
Adjust or establish hot-oiling schedules for each well.
Make hot-oiling schedules available to all field personnel.
Post schedules and update as work is done.
Update and evaluate hot-oiling schedules annually.

Installing the hot-oiling procedure as recommended will reduce expenditures and eliminate duplication of work.

ESTABLISHING FREQUENCY

The number of times a well will require hot oiling is dependent on two factors. These are the cloud point and pour point of the oil the well is producing and the location, length, and pressure of the flow line the oil is moving through.

The cloud point and pour point are not controllable and must be monitored through chemical companies. The flow lines can be monitored and controlled. Flow line location, length, and pressure are key factors in determining when a well should be hot oiled.

VOLUME NEEDED

The capacity of a 3-in. line is 8.75 bbl/1,000 ft. This means that 25 bbl of oil are adequate for a 2,500-ft length flow line. A line 5,000 ft long will require 44 bbl of oil to completely heat the entire line.

Under the north sector's existing procedures, the 5,000-ft line would get only 25 bbl of oil.

This will heat only one half of the line and force the foreman to come back to hot oil the flow line before and after winter. By using the recommended procedure, the return trip to the well can be eliminated, thus reducing expenses.

Because the flow lines are buried in the north sector, the rapid changes in surface temperature will have little effect on the oil. Here, it will be necessary to install a flow line valve on each well if the wellhead accumulation is to be monitored. Monitoring the flow line pressures and wellhead accumulations will be the key to initiating this project on the north sector.

The west sector will need the reduction of the amount of fluid pumped down both the casing and flow line. The average well on the west sector produces 50 bbl of fluid/day. Pumping 75 bbl only in creases the time until the well returns to its original production.

The 2-in. flow lines on the surface increase operational problems for the foremen. The capacity of a 2-in. flow line is 3.9 bbl/1,000 ft. Using the recommended 10 bbl/1,000 ft will more than double the volume pumped into the flow line.

The problem with the Dean A lease is that some wellhead pressures are difficult to monitor due to back-pressure valves installed on the flow line. This increases the need to pull check valves at the wellhead and satellite to monitor paraffin accumulation.

GUNBARREL PROBLEMS

The Southwest Levelland unit is in the same condition as the Dean A. The west sector has also been experiencing an increase in paraffin accumulation since the installation of gunbarrels on the Dean A and XIT units.

Adding a paraffin solvent to the oil pumped down the flow lines will increase the paraffin removal from the system. In the past, paraffin solvent has not been added to the oil, allowing the paraffin to precipitate after it was removed from the flow lines.

The precipitate causes operational problems such as thick interfaces in the gunbarrels. Reducing gunbarrel problems will allow the pumper and foreman to have more time for other tasks.

ECONOMICS

Both sectors currently have good hot-oiling programs. However, with a small adjustment to the recommended procedure, the area's hot-oiling expenses will be reduced by $26,163 (11.2%).

This reduction is based on hot oiling each well on the north and west sector an average of four and three times per year, respectively. The north sector will reduce hot oiling by $7,498 and chemical usage by $10,202.

The west sector will reduce hot oiling by $10,544 but will increase chemical usage by $2,081. The increase in chemicals is because in the past no chemicals have been added to the oil in the west sector.

The savings in hot oiling is a minimum that will be realized. As each well's schedule is established, the savings will be even greater. Calculations are shown in Table 9.