A U.S. Eagle Ford Shale operator experienced downhole paraffin deposition in recently completed shale oil wells. The deposition occurred in the tubulars and in the flowlines. To control deposition, the operator added to the fracture a proppant-like slow-release particle onto which a paraffin inhibitor had been adsorbed. The particle is designed to slowly release the adsorbed paraffin inhibitor into the bulk oil as it flows through the propped zone and to inhibit paraffin deposition.

The prior practice in this field was to complete the wells and then apply a paraffin treatment and remediation program as necessary. In the offset wells to which the solid product was compared, the operator normally saw paraffin deposition after about three months of production. The operator selected 17 wells for completion using the solid paraffin inhibitor. After 10 months of production, the operator has noted no paraffin-related issues.

An inert, highly adsorbent proppant-sized substrate that has been treated with a concentrated paraffin inhibitor is pumped with the proppant during a hydraulic fracture. The substrate is handled as a proppant. Upon placement in the proppant pack and upon initial hydrocarbon production, the paraffin inhibitor slowly desorbs from the substrate into the bulk hydrocarbon phase of the produced fluids. As long as this chemical desorption occurs at a temperature above the wax appearance temperature (WAT) of the crude oil, the paraffin is inhibited for the finite life of the treatment.

Benefit of treatment

In all flow assurance programs a cost-to-benefit ratio exists. Simply put, the cost of preventing flow assurance problems must be less than the total cost of the problem. When multiple competitive flow assurance programs are presented, the operator must select between the most cost-effective of the various choices. In the case of downhole paraffin inhibition, the operators in many areas, including the Eagle Ford, have three basic choices:

  1. Add the solid paraffin inhibitor during the hydraulic fracture;
  2. Treat downhole with a liquid paraffin inhibitor; or
  3. Use mechanical and/or thermal treatments as needed to remove precipitated paraffin from the wellbore.

There is not a hard and fast rule regarding the metrics used to evaluate the most economic choice. For the subject wells the operator calculated that if the solid paraffin inhibitor worked for six months, the operational and economic benefit would exceed the cost of the treatment. At present this threshold has been met and exceeded with the initial treatments.

Theory, material and method

Paraffin remains in solution as a function of pressure, temperature and the presence of lighter hydrocarbons that act as solvents. When the pressure drops during production, the temperature drops as a function of the lowered pressure and the lighter hydrocarbons gasify under reduced pressures, the entire equilibrium system of the crude oil changes. One of the results is the shedding of the heavy paraffins that are no longer soluble in the fluid. The deposited paraffins are then an operational concern.

Paraffin inhibitors are molecules designed to kinetically inhibit seed crystallization and mass agglomeration. That is, they forestall the growth and deposition of paraffin for some period of time. From a practical standpoint the operator needs enough time for the oil to move from the wellbore to the surface facilities. The degree of inhibition depends on the deposition characteristics of a particular crude and the formation characteristics. Finally, the paraffin inhibitor must be present in an amount sufficient to kinetically inhibit all of the paraffin molecules that form deposits as thermodynamic conditions change in the well.

In the case of the solid paraffin inhibitors, there must be sufficient inhibitor present in the oil production pathway. That is why the material is placed in the proppant. The proppant pack creates the pathway for the oil to flow from the formation to the perforations. As the oil passes through the proppant pack, the paraffin inhibitor on the solid substrate desorbs into the oil. Almost by definition the temperature at this point is above the WAT, and therefore the oil is inhibited before the onset of wax crystallization. The inhibited oil now proceeds to pass through the perforations, where the greatest pressure and cooling occurs. Inhibited paraffin stays in solution through the perforations, into the wellbore, up the tubulars and into the surface facilities. By initiating inhibition in the proppant pack, the amount of wax deposition is minimized to prolong or avoid any remediation or loss in production.

The solid paraffin inhibitor substrate is added on-the-fly during the proppant addition stages of the hydraulic fracture. The stimulation engineer calculates the addition rate of the proppant and then calculates the rate of the solid inhibitor. Thus, as the proppant feed rate ramps up or down, the solid inhibitor tracks that ramping. This assures an even distribution of the solid throughout the proppant pack. If the product was added in a random fashion, there could be pockets of the proppant pack with a high concentration of inhibitor. This could affect both fines generation and the total contact area of the inhibitor material by the produced crude.

Once the hydraulic fracture is complete and the well is put on production, a service technician makes regular stops at the subject well to collect a sample of the produced crude oil. Ideally, the operator will identify an offset untreated well that can be used as a standard for comparative purposes. The thinking is that the paraffin inhibitor should depress the pour point of the crude oil relative to an untreated sample. Over time this pour point data produces a trend line. That line should trend downward to indicate less and less inhibition due to the consumption of the inhibitor.

Another measure that was employed was to characterize the well samples by the oil fraction with hydrocarbon molecules greater than C18. This measure did not identify any significant difference between the treated and untreated production. There are ongoing internal studies to find a dependable manner by which to measure the remaining treatment life of the solid substrate. In the field there is also an effort to isolate crude sampling points for untreated crude to establish benchmark metrics for the untreated production vs. treated production.

Once the substrate is determined to have given up all of the paraffin inhibitor, the operator needs to first evaluate the extent of the current paraffin production and, if warranted, implement a traditional paraffin inhibition program.

In summary, the solid paraffin inhibitor substrate placed in a proppant pack during the hydraulic fracture process will release sufficient inhibitor into the crude stream during well production to provide paraffin inhibition for a time sufficient for the operator to recover the treatment costs and avoid operational and deferred production costs associated with paraffin remediation. The length of this treatment life is monitored using a comparative, indirect method in addition to observing production system changes that might indicate the onset of paraffin deposition.

FIGURE 1. This image shows a flowline after three months of using flowline inhibitor. (Source: Baker Hughes)

Results

Figures 1 and 2 are photographs showing the interior of two flowlines from two different wells from the Eagle Ford lease containing the wells treated with the solid paraffin inhibitor. They draw the comparison between a well with paraffin deposition problems and a well that does not have deposition problems due to an effective inhibition program. In Figure 1 the operator experienced problems related to paraffin deposition. The photograph shows the inside of a flowline downstream of the wellhead. The wax accumulated in the flowline had also shown up in downhole and surface facilities. The photo was taken after three months of well production. It had been fractured. The flowline was treated with a paraffin inhibitor that did not appear to be effective. The paraffin problems manifested in this well provided impetus to look for a flow assurance solution.

The flowline shown in Figure 2 was opened after three months of production to see the extent of any deposition. This well had been fractured using the solid paraffin inhibitor. As of September 2013 the well was still producing without indications of paraffin deposition.

FIGURE 2. After three months of using a solid inhibitor, there is no paraffin buildup. (Source: Baker Hughes)

At the time of publication the oldest of the 17 wells fractured using the solid paraffin inhibitor had been producing paraffin-free for 10 months. In addition to these wells there are several offset wells that were completed prior to using the solid paraffin inhibitor. The operator did experience paraffin-related problems for those untreated wells.

Recently the operator reported it had cut paraffin on eight offsets (wells not fractured using the solid paraffin inhibitor). While the wireline unit was in the field, the production engineer told the crew to include one of the first wells that had been fractured with the solid paraffin inhibitor. The wireline operator reported there was no paraffin in the tubing when he placed his cutter in the well.

Discussion

The development of flow assurance technologies is a natural outgrowth and response to the challenges presented in the production of oil and gas. The combination of factors that lead to flow assurance problems is large. Pressure and temperature changes combined with the crude characteristics determine the amount and location of paraffin deposition. When paraffin deposits, it tends to constrict flowlines and tubulars. This shows up in reduced flow and increased back pressure. At some point the problem calls for remediation. The cost associated with remediation and deferred production is the financial driver that leads operators to look for alternative methods to control the total paraffin handling costs. The solid paraffin inhibitor substrate highlighted in this paper has been applied in more than 2,000 wells, primarily in the U.S. and Canada. In all cases the operators have either reported satisfaction or are waiting for a longer time period to pass before making the final evaluation. This technology is limited to wells that are hydraulically fractured. The product addition rate is limited based on an evaluation of the conductivity impact. However, for wells that fit the application criteria it is a technology that has reduced overall production costs by reducing both workover costs and the cost of deferred production.

Acknowledgments

The authors want to acknowledge Dora Galvan, Clayton Sullivan, Cash Carlisle and Dr. Dong Shen.

This paper originally appeared as SPE 168169 and has been reprinted with permission.

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