Test methodology to ensure adequacy of barium sulfate scale treatment

In a Permian Basin case study, scale stress testing provided a more accurate assessment of scale inhibitor effectiveness, enabling optimization of a waterflood program and enhancing asset integrity.

Kent Caudle, Champion Technologies

Enhancement of crude oil production via waterflooding is a standard operating practice in the Permian Basin of West Texas, where secondary recovery methods, by some estimates, account for as much as two-thirds of regional oil output. Waterflooding technology was introduced to the basin in the 1950s, and, as operators have refined waterflooding technology during the intervening decades, effective water management has proven to be a crucially important element of primary and secondary recovery projects alike.

Accessing adequate sources of makeup water for a waterflood can be especially problematic in arid West Texas. As a result, waterflood operators frequently are forced to use source water that can cause production and/or environmental issues when mixed with fluids encountered in targeted reservoirs. Mixing incompatible waters inevitably creates conditions in which scale deposits can form in production systems and adhere to the surfaces of production components, resulting in such problems as flow restrictions and plugging, corrosion, equipment damage and even formation damage.

Several effective scale-inhibition chemistries have been developed and deployed on Permian Basin waterflooding projects to prevent formation of a variety of scale deposits. However, decades of expansion of waterflooding projects in the region gradually have forced waterflood operators to rely more and more upon makeup water from sources containing contaminants that can render traditional scale inhibitors ineffective.

Some oilfield specialty chemical companies have responded to this new challenge by more thoroughly evaluating the composition of available water sources and reservoir fluids, by developing new scale-inhibition chemistries that allow mixing of otherwise incompatible fluids, and by devising or adapting advanced testing methodologies that allow direct measurement of scale inhibitor effectiveness and treatment optimization.

SCALE FORMATION AND TREATMENT OPTIONS

In essence, scale deposits are crystals of minerals that precipitate from supersaturated solutions of fluids containing complementary electrolytes needed to form scale. In addition to mixing of incompatible waters, other factors that influence scale formation include changes in temperature, pressure or pH. Corrosion byproducts such as iron sulfide or iron carbonate also can cause scale to form.

Scale deposits can form whenever a supersaturated solution contains a greater amount of solute—such as ions of barium (Ba²⁺), calcium (Ca²⁺), strontium (Sr²⁺), carbonate (CO₃²⁻) or sulfate (SO₄²⁻)—than should be present at equilibrium. Molecules in such supersaturated solutions come together randomly in a process called nucleation to form small aggregates; molecules of precipitate aggregate to form scale crystals; and scale deposits ultimately are formed when crystals adhere to exposed surfaces.

Oilfield chemical companies have developed three general types of chemical products to mitigate scale issues: chelating or sequestering agents, threshold inhibitors and dispersants. Chelating or sequestering agents function by complexing with the cations present to render them unable to interact with anions of sulfate (SO₄²⁻) or carbonate (CO₃²⁻) to form scale.

Threshold inhibitors work by inhibiting nucleation or by modifying crystal growth. The proposed principle for nucleation inhibition holds that an initially formed aggregate can be made unstable by adsorption of a scale inhibitor, causing the aggregate to fall apart and return the scaling ions into solution. Crystal growth modification theory hypothesizes that crystals have preferred locations of growth, so crystal growth modifiers function by slowing the growth rate and by distorting crystals to diminish their ability to adhere to surfaces. Dispersants aid in preventing crystal adherence and growth by coating and dispersing scale crystals, which discourages aggregates from forming.

However, some types of scale inhibitors are susceptible to poisoning or deactivation in the presence of high amounts of calcium, magnesium or iron. Other inhibitors might be very resistant to such contamination but still be ineffective at inhibiting the particular type of scale that is causing issues. So before implementing a scale control program for a waterflood project, it is crucial to thoroughly analyze the properties of both the source water to be used for makeup and reservoir fluids to verify their compatibility.

Phosphate ester-based and phosphonate-based scale control chemistries have been developed and used successfully for many years to control scaling at West Texas waterflooding projects, and general guidelines have been established that correlate fluid saturation indices with rates of scale formation.

Scale inhibitors are often injected into a waterflooding system continuously, because inhibitor concentrations must remain at specified minimal levels—as little as a few parts per million (ppm) in most applications—to be effective. Dosage levels of phosphate ester and phosphonate scale inhibitors used traditionally in the Permian Basin are confirmed by monitoring inhibitor residuals present in fluids produced to the surface.

However, residual monitoring is an indirect measurement method that does not allow some important performance parameters to be tracked, and monitoring residuals of some new scale inhibiting chemistries—polymer-based inhibitors, for example—is extremely costly and difficult to master at the low concentrations required for treatment.

When traditional scale inhibitors and testing methods can’t provide the level of performance required, less common, advanced lab and field methodologies—such as scale stress testing, particle size distribution, and percent inhibition testing via atomic absorption spectroscopy—are viable alternatives.

CASE STUDY

A Houston-based independent operating company needed a new source of makeup water to support a multiphase expansion of an established waterflooding project in Stonewall County, Texas.¹ Most of the existing wells in the waterflood had produced oil for many years from the Canyon Sands Formation, including some wells drilled nearly 70 years ago.

Dozens of new wells were envisioned, which meant existing makeup water sources would become inadequate. A new source of makeup water would have to be cost-effective to access, abundant and as compatible as possible with Canyon Sands fluids, which contain an abundance of naturally occurring barium.

The advanced age of some facilities in the field complicated the company’s objectives. Casing leaks had become increasingly problematic over time. In each such incident, an influx of sulfate-laden water mixed with barium-laden fluids from the Canyon Sands Formation (Table 1), triggering severe barium sulfate scaling issues.

TABLE 1.  Representative water analysis of Canyon

Makeup water source A. The operator first considered sourcing supplemental makeup water from water wells in the area because it was an easily accessible and plentiful source. However, the well water contained high concentrations of dissolved sulfate, and scale predictions calculated using ScaleSoftPitzer analytic software (see sidebar) revealed that commingling well water with Canyon Sands reservoir fluids would result in saturation indices greater than 3.0, or about 1,000 times the saturation threshold.

Based upon previous calculations correlating saturation indices with scale formation, the service company knew that barium sulfate scale often begins to form at a saturation index of 0.3, which is about two times saturation. Inadequate scale inhibition almost certainly would result in rapid and severe barium sulfate scaling issues if well water was used.

Lab testing was performed to determine if the barium sulfate scale could be inhibited at a saturation index of 3.0 or greater. First, four identical mixtures of a water sample containing sulfate and a water sample containing barium were prepared. Each mixture was treated, respectively, with a phosphate ester inhibitor, two phosphonate scale inhibitors, and a polymer scale dispersant, at a dosage of 100 ppm. Polymer scale inhibitors were not considered due to high cost and the difficulty of monitoring low-level residuals.

After some time had passed, the four samples were filtered using 0.45-µm millipore filters to remove any barium sulfate crystals that might have precipitated; then each treated sample was analyzed using atomic absorption spectroscopy for the presence of dissolved barium. The barium content of each treated sample was compared to the barium content in the original barium-water sample, and the results were reported as percent inhibition.

The phosphate ester scale inhibitor proved to be the most effective of the treatment chemistries analyzed, retaining 84.5% inhibition. Phosphonate scale inhibitor A retained 4.0% inhibition; phosphonate scale inhibitor B retained 16.5%; and the dispersant retained zero inhibition.

The mixed water sample treated with the phosphate ester scale inhibitor was tested further using a particle analyzer to determine the sizes of the scale particles the inhibitor allowed to form and their relative abundance. Suspended particles must be minimal in size and abundance to prevent formation damage and to ensure the integrity of the water-injection system.

An untreated sample of mixed water, a mixed water sample treated with a polymer scale dispersant, and a mixed water sample treated with a mixture of phosphate ester and polymer dispersant also were tested using a particle analyzer. Again, the phosphate ester chemistry exhibited the best results by having both the lowest count of particles per 100 ml of solution (176,782/100 mL) and the smallest particles, Fig. 1.

Fig. 1. Results of particle size distribution analysis using a particle analyzer.

Testing indicated that the phosphate ester chemistry could be used fieldwide to control barium sulfate scale. But the high risk of barium sulfate scale forming in the aftermath of casing failures was a powerful disincentive to using high-sulfate well water as a source of makeup water, and the operator opted against using it.

Make-up water source B. Instead, the production company chose to drill a well to investigate a deeper water-bearing interval in the Canyon Sands Formation. Initial analysis of water from the Lower Canyon Sands interval found that it did not significantly affect the saturation index for barium scale, making it a compelling candidate for makeup water. However, the Lower Canyon Sands water also contained high levels of calcium, magnesium, chloride and iron, which would make it incompatible with either phosphate ester-based or phosphonate-based scale inhibitors, Table 2.

TABLE 2.  Representative water analysis of Lower Canyon Sands Formation

Samples of Lower Canyon Sands Formation water were collected on a monthly basis in the field to monitor water quality and to accumulate enough solids for analysis. Back in the laboratory, millipore filters were soaked in warm HCl at a pH of 4, and multiple millipore filtration tests were run on the water samples. Accumulated solids were analyzed both qualitatively and quantitatively for the presence of phosphate, calcium and iron.

Initially, the precipitated phosphate ester was thought to be carbonate scale. Eventually, the phosphate ester was determined to be reacting with the dissolved iron and precipitating out. The acetic acid-soluble content, which is generally categorized as carbonate, was high because the precipitated phosphate ester would re-dissolve in acetic acid solution.

The precipitation of phosphate ester with dissolved iron was further confirmed through additional lab testing. Phosphate ester was added to a sample of Lower Canyon Sands water and left static for about 24 hours. The precipitate that accumulated was filtered and dried, and then dissolved in acidized, deionized water

The dissolved iron and phosphate content was then determined using standard bench test methods. Results indicated a high concentration of both species (about 11% and 35% abundance, respectively), which meant that the standard phosphonate and phosphate ester chemistries typically used to control scale in the area were all incompatible with the Lower Canyon Sands water.

Polymer-based scale inhibitors. Polymer scale inhibitors were then considered as an option for treating commingled Canyon Sands and Lower Canyon Sands Formation water.

A polymer scale inhibitor was selected based on additional properties of resistance to deactivation by interacting with ferric iron. Performance tests were carried out on the phosphate ester and polymer in a dynamic flow loop using synthetic brine that was formulated based on an analysis of the formation water. Both fluids were tested at 35 ppm, 30 ppm and 25 ppm.

Synthetic brine containing barium was commingled in the dynamic flow loop with synthetic brine containing sulfate. In the testing procedure, the scale inhibitors were studied initially at high dosage rates; dosages were then incrementally decreased until scale began to form in the scale coils of the dynamic flow loop, Fig. 2.

Fig. 2. Diagram of the dynamic flow scale inhibitor efficiency test apparatus.

The rate of scale formation was determined by monitoring the inlet and outlet line pressures of the scale coils. When scale began to form and adhere to the internal surface of the scale coils, a pressure differential occurred, with the inlet pressure increasing and the outlet pressure decreasing, indicating that inhibitor concentrations were below the minimum effective dosage.

In dynamic flow loop testing, the polymer exhibited a minimum effective dosage of 35 ppm. The phosphate ester had a minimum effective dosage of less than 25 ppm. Although the phosphate ester outperformed the polymer in effective minimum dosage, compatibility testing revealed that the phosphate ester was incompatible with Lower Canyon Sands water at a dosage as low 10 ppm, while the polymer scale inhibitor didn’t show signs of incompatibility until the concentration reached 1,000 ppm, many times greater than the minimum effective dosage demonstrated, Table 3.

TABLE 3.  Results from water/scale inhibitor compatability test

As a result, the polymer scale inhibitor was recommended for treating the Lower Canyon Sands water. However, there is no practical way of determining the minimum inhibitor concentration for treated fluids on a per-location basis by monitoring scale inhibitor residuals alone.

SCALE STRESS TESTING

Fortunately, extensive research is being conducted to develop economical and time-saving methods for monitoring low-concentration residuals of polymer scale inhibitors. The alternative monitoring method chosen for use in the Permian Basin is referred to as a scale stress test.

A scale stress test enables determination of the capacity of treated fluids to inhibit scale formation on an individual location basis. The limiting reactant—in this case study, sulfate—is added incrementally to the treated fluids until there is no longer enough scale inhibitor to prevent scale formation. The testing protocol directly quantifies how much additional sulfate the treated fluids can tolerate before scale begins to form. By determining the threshold where barium sulfate scale begins to form, a minimum effective dosage can be established empirically on a sample-point-by-sample-point basis in a relatively short amount of time.

One of the main goals of the scale stress test is to develop a procedure that is simple, does not require additional analytical equipment, and can be completed in a relatively short period of time. For these reasons, the current desired method for interpreting scale stress test results is through visual observation. If no haziness or precipitate can be observed, a sample passes a stress test; if significant haziness or precipitate is visible, the sample fails the test; in cases where minimal haziness or minimal precipitation is observed, inhibitor effectiveness is considered marginal.

In Fig. 3, each data point represents one of 20 fluid samples that underwent scale stress testing. In each stress test, visual observations were made categorizing a sample as passing, marginal or failing. Additionally, the percent inhibition was determined using atomic absorption spectroscopy. Figure 3 compares visual observations with values indicated by atomic absorption spectroscopy.

Fig. 3. Results of the scale stress test for 20 samples. The graph compares visual observations of haziness or precipitate with percent inhibition as determined using atomic absorption spectroscopy.

Certain laboratory techniques being used to prepare samples for visual observation are still under review and subject to revision. However, this approach eliminates the need for time-consuming analyses using sophisticated equipment, and allows stress tests to be performed in the field.

For the Canyon Sands waterflood expansion, stress tests were conducted by adding known amounts of sulfate (SO42−) at different concentrations to samples of treated water containing barium. The amount of dissolved barium was determined in samples that had been spiked with a known amount of sulfate and in one sample that was not spiked with sulfate. A significant decrease in dissolved barium content of a tested sample would indicate that the inhibitor concentration was not high enough to prevent barium scale formation, and the sample would fail the stress test.

The solubility of barium sulfate is extremely low, 2.5 mg/L at 20°C. It has a solubility product constant (Ksp) of 1.1 x 10−10, compared, for example, with a Ksp of 4.93 x 10-5 for calcium sulfate. But it increases significantly with only a small increase in the concentration of sulfate, Fig. 4.

Fig. 4. Analytic software was used to model the change in the barium sulfate scaling index with the addition of sulfate.

This characteristic can be used as a tool to determine what impact the addition of sulfate has on the scaling tendencies of fluids.

Test results demonstrated that temperature plays an important role in the determination of barium sulfate scaling tendencies. As the temperature increases, barium sulfate scaling tendencies, as measured by the scaling index, decrease linearly at a significant rate. Barium sulfate scale formation is unaffected by changes in pH, so this parameter was not considered when performing stress tests. Although pressure exhibits relatively low impact on barium sulfate scaling tendencies compared to other factors, an increase in pressure slightly decreases the scaling tendencies for barium sulfate formation.

The considerable influence of temperature on barium sulfate scaling tendencies provides a greater degree of certainty for stress testing the capacity of a polymer scale inhibitor to control sulfate scaling, because stress testing on Lower Canyon Sands Formation water is performed at room temperature (about 75°F) at 1 atm. By contrast, the temperature of the Canyon Sands Formation ranges between 90°F and 105°F. Thus, performing the stress tests at room temperature results in a more severe test.

For this application, stress testing determined that a minimal capacity to inhibit scale could be set on an individual location basis. This capability was especially important due to unplanned infusions of sulfate-bearing water resulting from casing failures. The ability to continue inhibiting barium sulfate scale even when excess sulfate enters the production system due to anomalies such as casing leaks can provide an extra measure of assurance to any scale inhibition program.

Based on the test results described here, the polymer scale inhibitor program was initiated at the Canyon Sands waterflood in June 2009. It is currently treating 45 wells in the field. Since initiation of the program, the waterflood operator has experienced no barium sulfate scale issues and is proceeding with a third phase of waterflood expansion.

This case study demonstrates that less common lab and field methods—such as scale stress testing, particle size distribution and percent inhibition testing via atomic absorption spectroscopy—are viable alternatives to scale inhibitor residual monitoring. When implemented properly, such advanced testing protocols can provide useful guidance for developing and optimizing scale control programs.

LITERATURE CITED

 ¹ Caudle, K., Hardy, J., Varner, D. and T. Latham, “Case study of effective sulfate scale control in a severe scaling environment utilizing alternative field and laboratory techniques,” presented at the Southwestern Petroleum Short Course, Lubbock, Texas, April 21–22, 2010.

THE AUTHORS
	Kent Caudle is a Technical Representative in the Western US region of Champion Technologies, where he serves as a project lead for major proposals and critical projects in the Permian Basin; provides technical training; and presents seminars for various customers. A Champion employee for the past six years, Mr. Caudle’s work focuses on problem solving, account profitability and product line consolidation.