Technology

solids control remains one of thSolids control is one of the most critical elements of well construction. (Image source: Adobe Stock)

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.

Middle East assets face the threat of corrosion. (Image source: Adobe Stock)

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.

Under the contact, Halliburton will deploy intelligent automation solutions for fracturing to optimise performance in real time and support disciplined implementation across multi-well campaigns.

In line with its ambitions to grow gas production by more than 60% by 2030 compared to 2021 levels, Aramco has awarded Halliburton a multi-year contract to deliver integrated stimulation and completion services for unconventional gas development in the Kingdom of Saudi Arabia

This award is part of a broader multi-billion contract, supporting one of the largest unconventional gas development programs globally, at the heart of which is the Jafurah unconventional gas development. The Jafurah field contains 229 trillion scf of gas-in-place and 75 BSTB of condensate-in-place. Production started in December 2025, with an ambition to ramp-up and deliver two billion scfd of sales gas by 2030, along with 420 million scfd of ethane, and around 630,000 barrels per day of gas liquids and condensates.

This award builds on Halliburton’s established portfolio supporting Aramco’s unconventional program. The company delivers a comprehensive suite of drilling and completion solutions across many of the Kingdom’s unconventional plays. This collaboration supports broader regional efforts toward integrated unconventional development programmes.

Operators in unconventional reservoirs and high-pressure environments require precision and speed to lower costs per well and improve production consistency. Halliburton’s hydraulic fracturing services combine reliable surface operations with scalable subsurface solutions that help reduce nonproductive time and support predictable execution.

Under the contact, Halliburton will deploy intelligent automation solutions for fracturing to optimise performance in real time and support disciplined implementation across multi-well campaigns supporting digital integration across operations while advancing efficiency and operational reliability.

OCTIV services are at the core of Halliburton’s intelligent fracturing ecosystem. OCTIV digital fracturing services enable frac automation, digital operations, and remote connectivity across all aspects of Halliburton’s hydraulic fracturing business. The services enable intelligent automation to maximise the performance and efficiency of equipment and operations. OCTIV automates digital workflows, information, and equipment across all aspects of fracture operations, for enhanced safety and efficiency.

While the Sensori fracture monitoring service is an easy to deploy, cost-effective fracture monitoring solution for continuous measurement and visualisation of the subsurface. It combines non-intrusive technologies, advanced data acquisition and processing, and real-time answers into a single, cost-effective solution that empowers operators with unparalleled visibility and control over fracture performance.

"This award highlights our long-standing collaboration with Aramco and builds on more than 80 years in the Kingdom, while advancing unconventional gas development in the Kingdom. Beginning in the third quarter of 2026, Halliburton will deploy the Kingdom’s first fully integrated intelligent fracturing platform through OCTIV Auto Frac and Sensori fracturing monitoring services to contribute to asset value for one of the world’s largest unconventional fields,” said Rami Yassine, president, Eastern Hemisphere, Halliburton.

To support development activities in the Jafurah Basin, Halliburton plans to increase its investment in local manufacturing, improve its supply chain, and expand workforce development programs within the Kingdom, in line with Vision 2030 objectives, aiming to scale operations and sustain high performance as unconventional activity accelerates.

The platform will show how Geoteric’s solutions for AI-based interpretation of seismic data can be connected with simulators from SINTEF. (Image source: Geoteric)

Geoteric and SINTEF have entered into a collaboration to develop a new AI agent platform based on open standards, which will make it possible to connect seismic interpretation directly with reservoir simulation

The platform will show how Geoteric’s solutions for AI-based interpretation of seismic data can be connected with simulators from SINTEF, enabling users to move more quickly from geological interpretation to dynamic reservoir simulation in a single shared workflow. The collaboration combines the expertise of Geoteric in AI-based interpretation of seismic subsurface data, withSINTEF’s experience in reservoir simulation, mathematical models and research-based software for complex physical systems.

The solution represents an important step towards a new generation of integrated workflows, in which AI agents collaborate across disciplines to combine interpretation, modelling, simulation and decision support. The aim is to give geophysicists, geologists and reservoir engineers faster insight, facilitating decision-making and management of uncertainty throughout the workflow.

By automating the interaction between specialised agents, users can obtain more verifiable interpretations and clearer quantification of uncertainty. This makes it easier to assess alternative geological models, compare different scenarios and identify the solutions that provide the strongest basis for decision-making.

“I am convinced that open AI agent platforms will change the way geoscientists work. Based on my experience building the company that delivered Petrel to the oil and gas industry, I see this as an important next step for the industry - where specialised applications can collaborate seamlessly to provide better subsurface insight,” said Jan Grimnes, chair of Geoteric.

“The opportunities lie not only in automating individual tasks, but in enabling specialised tools to work together to test alternatives, reveal uncertainty and give decision-makers a stronger foundation. This is what we want to demonstrate together with SINTEF.”

“This collaboration is an exciting opportunity to operationalise the research we are doing in SINTEF Agent Lab on the use of AI agents as part of expert systems,” added Knut-Andreas Lie, chief scientist at SINTEF.

“For several decades, SINTEF has developed simulation methods and research-based software for reservoirs, CO₂ storage and other geoenergy systems. Much of this work is based on open-source code and has been adopted in collaboration with major international energy companies. In this project, we can combine that experience with new agent technology and show how open tools can be integrated into more automated and verifiable workflows.”

The results of the collaboration will be presented for the first time at the international geoscience conference, IMAGE in Houston in August.