Othman Soliman, founder, SC DrillTech, explains why treating solids control as an integrated processing system rather than as a collection of individual equipment can lead to meaningful gains in drilling performance, cost control and operational efficiency

In drilling operations worldwide, solids control remains one of the most critical yet frequently misunderstood elements of well construction. For decades, operators and contractors have evaluated solids control performance through the narrow lens of individual equipment: shaker screen API ratings, hydrocyclone separation cut points, or centrifuge bowl speed. While these metrics are not without value, they reveal only fragments of a much larger picture. The reality is that solids control must be measured, managed, and optimised as an integrated system — not as a collection of standalone machines.

The pitfalls of siloed metrics

When a rigsite team focuses solely on individual equipment performance, the results can be deceptively reassuring. A shale shaker may be running at its rated capacity, hydrocyclones may be delivering the expected underflow density, and the centrifuge may be operating within manufacturer specifications — yet the drilling fluid remains laden with fine solids, dilution rates are climbing, and non-productive time (NPT) is increasing.

This paradox occurs because each piece of solids control equipment is designed to remove a specific particle size range within a continuous processing chain. Shakers address the coarse fraction, hydrocyclones (desanders and desilters) target the medium range, and centrifuges handle the fine and ultra-fine solids. If any stage is misaligned — whether through improper feed distribution, incompatible screen selection, or fluid rheology that overwhelms downstream units — the entire system fails to deliver its collective potential.

The system approach: fluid volume, solids loading and retention time

A system-based evaluation begins with three fundamental parameters:
• fluid volume processed
• solids loading at each stage, and
• retention time across the surface system.

First, the total circulating volume must pass through the solids control equipment in a manner that matches each unit's design capacity. Overloading the shaker with high flow rates forces fine solids past the screens and into the active system, increasing the burden on hydrocyclones and centrifuges that were never intended to handle such volumes. Conversely, underutilisation of equipment leads to poor agitation and settling, creating dead zones where solids accumulate.

Second, solids loading must be tracked progressively. The mass of solids removed by the shaker directly influences the efficiency of the hydrocyclone bank. If the shaker is not removing coarse solids effectively, hydrocyclone nozzles plug prematurely, cone pressure drops, and separation efficiency collapses. Similarly, if hydrocyclones fail to remove medium solids, the centrifuge is forced to process a higher concentration of solids than its design allows, increasing wear and reducing fluid recovery.

Third, retention time across the surface system determines whether solids have sufficient opportunity to be removed before re-entering the wellbore. A system with inadequate surface volume, poor compartment agitation, or bypassed equipment will recirculate drilled solids regardless of how well individual units perform in isolation.

Impact on drilling performance and cost

Measuring solids control as a system directly affects two of the most closely watched metrics in drilling economics:
• rate of penetration (ROP) and
• dilution cost.

Excessive fine solids in the drilling fluid increase plastic viscosity and yield point, creating a thicker fluid column that reduces hydraulic efficiency at the bit. The result is lower ROP, higher equivalent circulating density (ECD), and an elevated risk of lost circulation or wellbore instability — particularly in the narrow margin windows common to deepwater, high-pressure high-temperature (HPHT), and unconventional formations globally.

From a cost perspective, every barrel of fluid diluted to control solids concentration represents a direct expense. When the solids control system operates as a cohesive unit, the volume of dilution required drops significantly. Field data from operations across multiple continents has consistently shown that improving overall system efficiency — rather than upgrading a single piece of equipment — yields the greatest reduction in dilution volumes and associated disposal costs.

Practical implementation on the rig

Transitioning to a system-based approach does not require capital-intensive overhauls. It begins with baseline measurements: capture the mass and particle size distribution of solids removed at each stage, compare it to the theoretical solids generated by the bit, and identify gaps.

Next, ensure that equipment is sequenced and sized correctly for the anticipated solids profile. A high-rate well in unconsolidated sands requires a different shaker screen and hydrocyclone configuration than a directional well in hard limestone. Fluid rheology must be managed to support — not hinder — mechanical separation.

Finally, establish clear accountability across the rigsite team so that solids control is treated as a shared objective rather than the sole responsibility of the mud engineer or solids control technician.

For operators and drilling engineers looking to stay ahead of evolving solids control practices, further technical resources and insights into system optimisation are available at SC DrillTech (https://scdrilltech.com), where continuous field-based research on solids control development is published to support industry advancement.

Conclusion

The complexity of modern drilling environments worldwide demands a shift in how solids control performance is judged. Individual equipment metrics will always have their place, but they cannot tell the full story. Only by evaluating shakers, hydrocyclones, centrifuges, and drilling fluids as a single, interdependent processing system can operators unlock meaningful gains in drilling performance, cost control, and operational efficiency. The question is no longer whether each machine is working — it is whether the system as a whole is winning.

Othman Soliman is the founder of SC DrillTech, an independent technical platform dedicated to Solids Control and Drilling Waste Management, with over 25 years of international field experience.

CorrosionRADAR has launched its CR:SR sensor solution, a new short-range sensor technology that expands its corrosion under insulation (CUI) intelligence portfolio and helps to transform CUI management from a reactive inspection activity into a proactive intelligence-led approach

The corrosion threat

Corrosion is an ever-present threat to asset integrity in the oil and gas industry, with industry studies estimating the global cost of corrosion exceeds $2.5 trillion annually. In the Middle East, the prevalence of sour gas, the increasing use of corrosive chemicals to enhance production and the push into high pressure, high temperature environments means that the corrosion threat is only intensifying in the region.
CUI, which is a particularly insidious form of corrosion as it is difficult to detect at an early stage, occurs due to moisture build up on the external surface of insulated equipment and structures, and is prevalent in the onshore and offshore oil and gas industries.

The benefits of predictive corrosion monitoring

Predictive corrosion monitoring solutions facilitated by advances in AI and digital technologies can help operators proactively manage their corrosion challenges and protect their assets, allowing them to monitor and predict risk remotely and make data-driven decisions, saving time and money, while enhancing safety and ensuring the longevity of critical infrastructure.

CorrosionRADAR is using this approach to transform CUI management with continuous monitoring and intelligence-based analytics that save time, improve uptime and reduce the risk of catastrophic failures.
Aramco for example is using CorrosionRADAR's CUI monitoring solution at its Ju'aymah NFL fractionation plant to monitor its assets and provide insights into the early and predictive detection of CUI, enabling plant engineers to address CUI issues more rapidly, improving safety and reliability, optimising inspection planning, and reducing the overall costs associated with future maintenance and shutdowns.

Remote sensor-enabled CUI monitoring programs help operators focus resources on the locations that matter most while reducing unnecessary inspection costs and operational disruption.

Targeted, localised monitoring

The new shortwave CR:SR sensor solution has been developed for targeted, localised monitoring without the need to remove insulation. It complements CorrosionRADAR’s existing CR:LR solution, which delivers permanently installed, long-range monitoring across vessels, columns, tanks, and other complex assets.

The sensor passes monitoring data to the AI-informed CR:CLARITY software for consolidation, analysis and reporting.

Together, the CR:LR and CR:SR sensors address the challenges of traditional inspection programmes by providing continuous visibility between inspection campaigns. CUI data is constantly collected and analysed by the CR:CLARITY software, enabling operators to prioritise inspection activity based on changing risk conditions rather than fixed inspection intervals.

Dr. Chiraz Ennaceur, chief executive officer at CorrosionRADAR, said, "At CorrosionRADAR, we recognise that every asset presents a different CUI challenge. Some assets require broad coverage across large areas, while others benefit from targeted monitoring of specific high-risk locations. By expanding our portfolio to include the CR:SR sensor solution and bringing all monitoring data together through CR:CLARITY, operators gain greater flexibility in how they monitor CUI while maintaining a single view of risk across their assets."

By combining multiple monitoring strategies through a single source of CUI intelligence, CorrosionRADAR aims to help operators move towards predictive, prescriptive, and ultimately more autonomous asset integrity management.

In a further boost for Iraq's oil and gas development prospects, Türkiye Petrolleri Anonim Ortaklığı (TPAO) is acquiring a 15% interest in BP Energy Company of Kirkuk Limited (BP ECKL), which is redeveloping several major oil and gas fields in the promising Kirkuk region of northern Iraq

Signed during the official visit of Iraqi Prime Minister Ali Al-Zaidi to Türkiye, the move builds on the strategic cooperation Memorandum of Understanding (MoU) signed by bp and Türkiye's national oil company in February 2026, and follows ConocoPhillips' recent acquisition of a 42% interest in BP ECKL. The two acquisitions bring together partners with complementary capabilities and expertise together with bp to support the next phase of redevelopment in Kirkuk. Following completion of the transaction, bp will remain the majority shareholder in BP ECKL with 43%.

Vast potential

Kirkuk, once among the most prolific regions globally, has vast potential, with a combined resource opportunity estimated at up to 20 billion barrels of oil equivalent.

bp received final government ratification for its contract to invest in the redevelopment of several giant oil fields in Kirkuk in March 2025, when bp said the investment will bring opportunity and growth to the Kirkuk region, as well as improving supply chain capability alongside job creation. Then bp executive vice president William Lin commented that the opportunity is fully in line with the company’s priority of pursuing new growth opportunities for bp as it strengthens and high-grades its portfolio across the world.

The contract between North Oil Company (NOC), North Gas Company (NGC) and bp includes the rehabilitation and redevelopment of the fields alongside investment in existing gas processing facilities, spanning oil, gas, power and water with potential for investment in exploration.

The Development and Production Contract covers an initial phase of oil and gas production of more than 3 billion barrels of oil equivalent from the Baba and Avanah domes of the Kirkuk oil field and the adjacent Bai Hassan, Jambur and Khabbaz fields in Federal Iraq, all currently operated by the North Oil Company (NOC) and North Gas Company (NGC). The contract area also includes additional exploration potential.

bp is drawing on its experience elsewhere in Iraq in developing Kirkuk, notably at the supergiant Rumaila field in southern Iraq, where with its partners it has helped to deliver a 40% increase in production since 2010. bp says it aims to grow a similar, modern upstream oil and gas industry centred around Kirkuk, bringing in technologies that transformed operations at Rumaila, such as real-time monitoring and digital surveillance. These can help to optimise well performance, predict and avert production issues, and facilitate data-driven decision making.

Chief executive officer Meg O’Neill said, “TPAO has been a trusted partner for more than 30 years through our work together across the Caspian region. This agreement builds on that long-standing relationship and, alongside our partnership with ConocoPhillips, positions us strongly for the next phase of redevelopment in Kirkuk. Kirkuk is a world-class resource base that can support Iraq's long-term energy ambitions, and we look forward to working closely with the Government of Iraq and our partners to deliver the next phase of redevelopment."

bp has a longstanding relationship with Iraq spanning more than a century with an involvement in both the north and south of the country. bp’s predecessor helped ‎Iraq to locate, produce and export oil from Baba Gurgur in Kirkuk, one of the largest oilfields ‎in the world at that time.