DIARYL DISULFIDE SOLVES SULFUR-DEPOSITION PROBLEMS AT SOUR GAS FIELD

Robert J. Voorhees
Exxon Co. USA
Houston

Eugene R. Thomas
Exxon Co. USA
Midland, Tex.

Kevin J. Kennelley
ARCO Oil & Gas Co.
Dallas

Use of diaryl disulfide (DADS) sulfur solvent was successful in removing sulfur from tubulars and flow lines at Exxon Co. USA's LaBarge field in Wyoming.

Additionally, the company's experience indicates that sulfur deposition can be a concern for gases with < 5% H2S and that phase behavior and well bore hydraulic models can be used to predict where, and how much, sulfur can be expected to be deposited.

Deposition of elemental sulfur in tubulars and flow lines can lead to decreased production, increased corrosion, and higher filtration-water disposal costs. These problems have been seen at LaBarge field even though its 5% H2S concentration is below a level at which sulfur deposition is normally a concern.

In its LaBarge application, Exxon found DADS to be preferable for sulfur-deposition problems because it was cheaper, less volatile, and easier to regenerate with no disposal needed when compared with the more commonly used solvent, dimethyl disulfide (DMDS).

LABARGE SITE

The LaBarge operation, located in southwest Wyoming, produces low-BTU sour gas from 17 wells on three federal leases (Fig. 1). The average gas composition is CO2 (66.5%), methane (20.5%), nitrogen (7.4%), H2S (5%), and helium (0.6%).

No associated liquid hydrocarbons are produced with the gas. The field was discovered in 1963 but considered noncommercial because of the low BTU content of the gas. Following gas-separation technology developments, Exxon committed to build a treating plant. It began field development in 1969 and commercial production in August 1986.

At LaBarge, the sour wet gas is gathered from the field, dehydrated in a central facility, and transported 40 miles to the treating plant at Shute Creek. The entire facility is operated remotely by a distributed control system (DCS).

Wells are produced through individual 8-in. flow lines from the well sites. The production from several adjacent wells is commingled at three manifold facilities.

At the manifold, free water is separated and sent to the central dehydration facility through a produced-water gathering system. The gas from the manifolds is also sent to the central dehydration facility via large-diameter trunk lines.

The wet gas and produced water are separated at the dehydration facility inlet slug catchers. Produced water is filtered and injected into disposal wells. The wet gas is dehydrated with triethylene glycol (TEG) and transported to Shute Creek via a 40-mile, dry-gas pipeline.

The treating plant (Fig. 2) separates the raw gas into marketable products: methane, CO2, helium, and sulfur. The plant processes about 600 Mscfd of inlet gas with products of roughly 120 Mscfd of methane, 230 Mscfd Of CO2, 3 Mscfd of helium, and 1,000 long tons/day of sulfur.

The wet-gas gathering system has several design features to mitigate corrosion from the wet acid gas. The primary protection is provided by a system continuously to inject corrosion inhibitor.

The inhibitor solution is blended in bulk at the central dehydration facility and distributed to each well site through a piping system. The solution is injected continuously at the wing valve to provide protection from that point to all points downstream.

The wellheads and downhole tubulars are constructed of high nickel content corrosion-resistant alloys (CRAS) and require no inhibitor for corrosion control. The carbon steel gathering system also includes a 0.25-in. corrosion allowance.

All pipelines in the system are equipped with pig traps to facilitate line pigging and are designed to accept smart pigs for corrosion monitoring. The facilities are equipped with on-line, retrievable corrosion coupons for monitoring. Surface piping at selected well sites includes a removable spool to correlate coupon results to actual pipe-wall corrosion. Surface piping includes the well site indirect fired heater, line choke, orifice meter, aboveground piping, and pig launcher.

SULFUR DEPOSITION AT LABARGE

Within 6 months of initial production in 1986, 3 of the 17 tubing strings showed significant flow restrictions.

Analysis of deposits from the surface chokes in these wells showed that the loss of production was because of sulfur deposition. This was unexpected because the 5% H2S concentration in the gas was below that at which sulfur deposition is normally a concern.

Over time, sulfur deposition was observed in the surface equipment and flow lines leaving the well sites. With the flow lines and vessels made of carbon steel, there was evidence from corrosion coupons that the sulfur was causing accelerated corrosion as had been seen elsewhere.1 3

By 1988, the water-injection wells were becoming plugged with sulfur that had bypassed the filters. These concerns led to a joint program between Exxon's southwestern division and Exxon Production Research to accomplish the following goals:

• Determine corrosion potential at LaBarge producing conditions in the presence of sulfur and the effectiveness of inhibitors at those conditions.

• Develop a model to determine where, and how much, sulfur would deposit in the well bores and flow lines over the life of the LaBarge field.

• Establish operational guidelines for managing sulfur deposition at LaBarge.

• Screen and field test potential sulfur solvents to remove deposited sulfur.

A series of autoclave corrosion tests was conducted to quantify the effect of deposited elemental sulfur on the corrosion of carbon steel and 316L stainless steel under simulated LaBarge flow line conditions. Tests were also conducted in the presence of two commercially available corrosion inhibitors.

The tests showed that elemental sulfur caused severe localized corrosion of carbon steel (60-135 mpy) at temperatures of 100-200 F. but had no effect on the corrosion of 316L stainless steel.

Both inhibitors tested were effective in lowering the general corrosion rate to less than 2 mpy for carbon steel; however, neither was able to prevent localized attack in the region of the sulfur drop.

These laboratory data confirmed the field experience that the highest corrosion rates were seen on carbon steel where sulfur deposits could accumulate, namely, on unpiggable portions of the flow lines. The pitting was worse in areas where flow had been shut-in for some time.

SULFUR-DEPOSITION MODEL

A Peng-Robinson-based model, similar in principle to that of Tomcej,4 was developed to predict the solubility of sulfur in gases as a function of temperature, pressure, and composition.

The primary purpose of the model was to determine where sulfur could be expected to deposit over the life of the field as a function of flowing conditions.

Outside of the normal calibration of an equation of state to match experimental data, there were two significant challenges: to obtain reliable experimental data on a high CO2 gas as is present at LaBarge at well bore and flow line conditions and to estimate the sulfur present in the reservoir gas.

For the first point, Alberta Sulphur Research was contracted to measure the solubility of sulfur in a synthetic LaBarge gas at temperatures and pressures representative of typical well bore and flowline conditions. These are presented in Table 1 along with the model predictions.

Two key observations from the data were that the LaBarge gas can hold two to four times as much sulfur as a low-CO2 gas with the same H2S content and that the sulfur solubility was undetectable at typical flow line conditions of 110 F. and 1,500 psi (< 1 lb/Mscf).

The model matched the literature data on sulfur solubilities2 3 5 6 generally to within 30%. The second challenge was to estimate the amount of sulfur in the reservoir gas. Once that is known, the model can be used to predict where, and how much, sulfur will drop out as a function of flowing conditions. Three methods were used to estimate the amount of sulfur:

1. Reviewing the wellhead conditions where sulfur deposition is a problem

2. Calculating the well bore conditions corresponding to observed sulfur build-up in one well

3. Looking at the amount of sulfur in the filters upstream of the water-disposal wells.

For the first method, it was observed that the model predicted < 0.3 lb/Mscf sulfur-holding capacity at the wellhead for the wells that had plugged. For the wells in which the rate was monitored to prevent plugging, the model predicted wellhead solubilities of 0.5-2 lb/Mscf.

These wells may be depositing sulfur at all rates but not enough to cause a plugging problem except at the higher ones. Most of wells with more than 2 lb/Mscf showed no tendency to plug and are not monitored for sulfur.

For the second method, a static caliper test was run on one plugged well bore to see where the sulfur was deposited. It was found that the sulfur began at 8,000 ft with the heaviest dropout at 6,000 ft. A model of the well bore under assumed flowing conditions gave temperatures and pressures corresponding to 1-4 lb/Mscf sulfur.

For the third method, a spot check of the amount of sulfur from the filters gave an estimated 1-2 lb/Mscf sulfur.

Therefore, although the sulfur loading may indeed vary from well to well, it appeared that the LaBarge gas holds 1-4 lb/Mscf sulfur.

It also appeared that keeping the flowrates at a level in which the predicted solubility of sulfur was greater than 0.5-1.0 lb/Mscf was generally sufficient to prevent plugging in the well bores. This typically corresponded to wellhead pressures greater than 2,000 psi. Fig. 3 shows how the sulfur solubility model can be combined with a well bore hydraulics model to predict sulfur-deposition conditions. It overlays the predicted temperature-pressure profiles for one well as a function of static bottom hole pressure on top of the sulfur solubility predictions.

The bottom hole conditions are on the top right portion of the curve and wellhead conditions on the bottom left.

Two key observations from the figure are the following:

• Sulfur solubility tends to rise with increasing temperature and pressure at well field conditions.

• The tendency for sulfur deposition will increase as the reservoir is produced and the static bottom hole pressure declines.

It is expected that wells which currently deposit sulfur only in the flow lines will begin to deposit sulfur in the well bores in a few years.

Some sour-gas operators have reported limited success in preventing sulfur deposition within production tubulars by restricting production rates. This reduces the pressure drop and usually increases wellhead temperatures.

In fact, for some wells at LaBarge, flowing at rates that kept wellhead pressures greater than 2,000 psi was effective at reducing tubular plugging problems. Fig. 4 shows this for one well in which reducing the flow rate from 50 Mscfd to 40 Mscfd is predicted to increase the wellhead pressure from 1,300 to 2,000 psi.

For some wells, however, keeping a 2,000-psi wellhead pressure is impractical even at reduced rates. These wells tend to plug with sulfur at any flow rate.

Since some wells plug at any rate and other wells will tend to plug in the coming years, a method of removing the sulfur was needed to ensure production. In addition, the sulfur deposits in the flow lines are a corrosion risk so that some method of cleaning them was needed as well.

For those reasons, possible sulfur solvents were screened and tested.

INITIAL TREATMENTS

In late 1986, two types of chemical sulfur solvents were commonly is use: amine-based and disulfide solvents.

Exxon Production Research conducted a series of tests at room temperature to measure the sulfur uptake of these chemicals at wellhead conditions with a simulated LaBarge gas.

It was found that the amine-based chemicals showed essentially no sulfur uptake, which is believed a result of the large amount of CO2 present.

On the other hand, DMDS showed uptake of 141 g sulfur/100 g DMDS.

Existing data showed that DMDS was not corrosive, but prior to field use, the compatibility of this compound with the elastomeric seals needed to be evaluated. A series of tests9 showed that the EPDM (ethylene dipropylene monomer) material used at LaBarge was not attacked by DMDS.

DMDS was then field tested on three plugged wells. Because LaBarge's production tubing is not equipped for continuous downhole chemical treatment, the solvent was batched down the wells.

The treatment consisted of spotting 16 bbl DMDS across the sulfur interval to a maximum depth of 8,000 ft with a nitrogen pad and flush. The wells were shut in for 1 hr and then flowed back through a portable well tester to recover the DMDS.

The wells were then brought back on-line and subsequent gauge-ring runs confirmed that the tubing strings were unobstructed.

The total cost for the three jobs was $87,000 and all were successful. However, personnel complained of the odor when doing the job, particularly in cleaning vessels and equipment. It also was important to reduce job costs as well as to find an easily regenerable solvent, if possible. The cost to dispose of the DMDS, which was not regenerated, was $30,000.

DADS EVALUATION

The wish list for a new sulfur solvent included:

• Good sulfur uptake at LaBarge conditions

• Inexpensive and readily available

• Nondamaging to production equipment and nonmetallic components

• Low vapor pressure to reduce losses to the vapor stream

• Easy to regenerate and dispose of, if necessary

• Easy to handle in terms of both odor and toxicity.

As will be discussed presently, DADS appeared to meet most of these conditions. In 1988, Alberta Sulphur Research mentioned ongoing work with DADS which is similar in structure to DMDS. Both are of the form:

R1 - S - S - R2

For DMDS, R1 and R2 are both methyl groups. DADS is a mixture of components in which R1 and R2 may be either aliphatic or aromatic groups.

It is a waste product generated from the caustic wash of sour naphthas in oil refineries. Millions of gallons of the material are generated annually.

The sulfur-uptake mechanism for DADS is quite similar to that for DMDS. A catalyst is used to break the sulfur-sulfur bond allowing for the incorporation of additional sulfur.

At room temperature, the sulfur uptake for DADS is considerably less than that of DMDS (25 wt % vs. 115 wt %). When DADS is heated to 180 F., however, the sulfur uptake increases to about 118 wt %.

As sulfur-laden DADS cools from 180 F. to room temperature, sulfur rapidly drops out of solution until saturation (25% loading) is obtained at room temperature.

DADS can be recycled through a temperature-control process, and large amounts of CO2 do not affect the sulfur uptake of the chemical.

Lab tests showed that DADS was noncorrosive to carbon steel and did not significantly degrade the EPDM 0-rings.

DADS also has a much lower vapor pressure than DMDS, which gives it less of an odor (though it is still objectionable) and less is lost to the vapor phase. DADS also costs less than DMDS.

Therefore, it appeared that DADS met the criteria for a better sulfur solvent to try at LaBarge.

FIELD TRIALS

Within 6 months of being treated with DMDS, the three wells became plugged with sulfur. Large accumulations of sulfur were also observed in the unpiggable portions of the flow lines at several well locations.

DADS was used to remove the sulfur from both the wells and flow lines.

Initial treatments with DADS were conducted in the surface flow lines in a circulating loop between the wellhead and the pig launch facilities. The flow lines were depressurized and a test spool removed to permit visual identification of the severity of sulfur deposition.

The spools were replaced and the solvent circulated between the wellhead and the pig-launching facilities at 175 F. for 1 hr with a pump truck. The DADS was collected in a vacuum truck and the spools were removed to determine if all of the sulfur had been removed.

In all flow line trials, all sulfur was effectively removed.

Downhole treatments were then conducted with DADS with a technique similar to that used with DMDS. The main differences were that the DADS was preheated to 175 F. before being pumped downhole, and after a job the DADS was sent to a storage tank for reuse.

A follow-up caliper log on the three wells showed that all the sulfur had been removed. Since these initial trials, DADS has been successfully used on numerous flow line and downhole treatments. The typical cost for a downhole treatment has dropped from $30,000 to about $3,000.

The major cost savers have been a lower-cost solvent (DADS vs. DMDS) and a simpler procedure (no longer perform the nitrogen pad and flush). In addition, the DADS has been "thermally regenerated" in the storage tank and hence successfully reused for multiple treatments. This also eliminated the cost of solvent disposal.

Future work will focus on automating some of the batch procedures and integrating the sulfur removal into the overall corrosion control program.

ACKNOWLEDGMENTS

The contributions of the following individuals are noted and appreciated: J. B. Hyne, Alberta Sulphur Research; W. Bruckhoff, BEB, Germany; R. C. Auld, Esso Canada Ltd.; J. M. Ross, J. E. La-Chance, B. E. Collins, R. M. Anderson, B. E. Williams, R. H. W. Powell, and D. Kihneman, Exxon's southwestern division; G. F. Gehrig and L. H. Novak, Exxon Production Research.

REFERENCES

1. Schmitt, G., and Bruckhoff, W., "Inhibition of Low and High Alloy Steels in the System Brine/Elemental Sulfur/H,S," NACE Corrosion '89 Conference, Paper 620, Apr. 17-21, 1989, New Orleans.

2. Kennelley, K., Smith, S. N., and Ramanarayan, T. A., "Effect of Elemental Sulfur on the Performance of Nitrogen-Based Oilfield Corrosion Inhibitors," Materials Performance, February 1990, pp. 48-52.

3. Bruckhoff, W., "State-of-the-Art Materials for Production of Sour Gas Containing Elemental Sulfur," U.K. Corrosion '85 Conference Paper, Harrogate, U.K., 1985.

4. Tomcej, R. A., Kaira, H., and Hunter, B. E., "Prediction of Sulphur Solubility in Sour Gas Mixtures," presented at the 39th Annual Laurance Reid Gas Conditioning Conference, Norman, Okla., Mar. 6-8, 1989.

5. Kennedy, H. T.. and Wieland, D. R., "Equilibrium in the Methane-CO,-H,S-Sulfur System," AIME, Vol. 219 (1960), pp. 166-169.

6. Roof, J. G., "Solubility of Sulfur in H2S and Carbon Disulfide at Elevated Temperature and Pressure," SPE J., Vol. 11 (1971).

7. Brunner, E., and Woll, W., "Solubility of Sulfur in H,S and Sour Gases." SPE J., Vol. 10 (1980), pp. 377-84.

8. Brunner, E., Place, M. C., and Woll. W., "Sulfur Solubility in Sour Gas," presented at the 60th Annual Technical Conference of the Society of Petroleum Engineers, Sept. 22-25, 1985, Las Vegas.

9. Kennelley, K. J., Abrams, P. I., Vicic, J. C., and Cain, D., "Failure Life Determination of Oilfield Elastomer Seals in Sour Gas/Dimethyl Disulfide Environments," NACE Corrosion '89, Paper 212, Apr. 17-21, 1989, New Orleans.

Copyright 1991 Oil & Gas Journal. All Rights Reserved.