Custom EOR reduces natural, synthetic damage to wellbore

Near-wellbore damage restricts production and negatively impacts operators’ revenue. It gets worse if there is a recurrence of damage caused by misdiagnosis because it could lead to an increase in capital and operating expenditures until they are above sustainable levels. As operators struggle to maximize production in the mature fields where they operate, the need for effective and complementary EOR solutions is great.

When the damage is done

Natural damage occurs over time during the decline of the well due to organic and inorganic deposits, which is common in mature oil fields as fluids and gases are drawn into the near wellbore and lead to various types of deposition. Synthetic damage is often the result of repeated stimulation and/or workover of the near wellbore to address a single challenge, e.g. inorganic scale, asphaltene, paraffin, emulsion, halite, and clay swelling.

Another factor in production impairment of the wellbore is liquid holdup. This occurs when water is drawn from the surrounding near wellbore into the tubing. Liquid holdup is the leading cause of the decline in low-pressure gas wells, when production is essentially choked off due to the hydrostatic head created by the unproduced water. Formation water can lead to corrosion issues and is often the source of seeding for organic scale when naturally occurring divalent captions such as calcium are exposed to CO2 over time.

FIGURE 1. This Clariant in-house core flow study shows a client’s field-specific lithology, measuring differential pressure in relation to the LIS-13212 concentration using nonpreserved core at an ambient temperature.

Clariant Oil Services offers a universal approach to diagnosing and delivering effective and sustainable control of near wellbore damage. To address each customer’s unique challenge, Clariant provides its LIBERATE Engineering Analytics and Diagnostics (LEAD) program.

Where there’s a well, there’s a way

The LIBERATE fit-for-purpose products and services are designed to function in complex environments and increase crude oil productivity in the near wellbore. The program draws from a custom-designed combination of inherently compatible solutions that can be applied continuously or in a multistage approach to address and prevent a combination of damage mechanisms. This approach offers an efficient process to return the near wellbore and tubing to its most productive state.

After assessing the historical performance, application options are determined. Application engineering is an important aspect of the overall near wellbore program. The company uses its LEAD process to create customized solutions for each of its customer’s challenges. This is accomplished through in-depth collaboration with the customer to define well history and devise the most appropriate type of solution in the design phase.

Applications are designed in this beginning stage, which includes recognizing the minimum inhibitor concentration and finding a way to maximize contact with the blockage and surrounding areas in a way that will provide longevity to the treatment, thereby reducing the intervention frequency.

Chemical analysis and measurement are important to the sustainability of a near-wellbore treatment. In the LEAD process, key performance indicators are agreed upon following the engineered design, and they are wholly aligned to the treatment program. The analytical tools guide the program’s problem definition and accurate data collection to measure and predict treatment efficacy and future damage onset frequency.

The final stage to ensure sustainability is diagnostics. Diagnostics allow both Clariant and the customer to provide health checks, ensuring cohesion between defined engineering and analytics steps.

FIGURE 2. This third-party core flow study of field-specific lithology measures the core flow permeability in relation to Clariant’s LIS-13212 concentration, using preserved core at field temperature. The 300 ppm LIS-13212 gave the same performance as 30,000 ppm CaCl₂.

The data and interpretation in the diagnostics phase provide insight to the entire program and allow for collaborative adjustments to be made in a dynamic process. Data capture, transparency, and routine discussions provide a platform for learning and adjusting to the specific near-wellbore requirements and changes. This stage is active and drives the decision-making process when re-evaluating the product, application, and analytics.

Following the LEAD

Recently, an operator using the LEAD program was able to fully customize its wellbore solution, ultimately allowing for the successful treatment of its wellbore casings. The operator came to Clariant Oil Services with a reservoir impairment issue. The operator’s field in Southern California was operating a secondary recovery waterflood process. The waterflood injection in the field had experienced cycles of different water blends throughout its lifetime, with waterflood injection salinity decreasing from 28,000 mg/l NaCl to 15,000 mg/l over the last few years. This drop was impairing injectivity into the deeper intervals of the reservoir and having a negative effect on crude oil production.

While the clay sensitivity had been studied through core testing, the injectors needed to be protected against potential clay swelling. The incumbent treatment plan called for soaking the new wells with CaCl₂ for several days prior to commencing injection and then continually injecting CaCl₂ into the injection water at approximately 7,500 mg/l to 10,000 mg/l to prevent clay swelling and loss of injectivity.

When Clariant presented the customer with its alternative clay-swelling protection strategy, internal core flow studies were performed (Figures 1 and 2) on field-specific core and on the Clariant LIBERATE product LIS-13212.

The results showed that by using low-salinity injection water with the addition of a defined low concentration of LIS-13212, a differential pressure increase in the core could be prevented by reducing clay swelling. Third-party core flow studies verified these results, and the operator decided to inject 300 ppm of LIS-13212 into the low-salinity injection water. Field application commenced and was successfully deployed to a waterflood of 60,000 b/d of water with no losses in injectivity, which provided significant value and cost savings for the customer.