New technologies, integrated approach add production from mature fields

GUILLAUME FAUCHILLE, Baker Hughes 

Fig. 1. Increasing production of mature assets can take months, compared to drilling-based FDP, which could take years.

Today, approximately 70% of oil and gas production comes from mature assets, and that number is expected to increase to 80% by 2030. As operators look to increase production with less capital investment, squeezing more from existing fields is an attractive option, but finding ways to boost output is not always easy. Achieving measurable gains over time requires new technologies and a different way of addressing the issues that restrict production in ageing assets.

A DIFFERENT APPROACH

There are compelling economic reasons to enhance output from existing assets. Brownfield production increases can be achieved in a shorter cycle than greenfield developments—yielding returns from weeks or months of planning instead of requiring years, Fig. 1. And most intervention and production enhancement programs cost normally less than $10/bbl, Fig. 2.

Another reason for taking a second look at production from mature assets is that it improves sustainability. Producing a greenfield barrel requires exploration, drilling campaigns, a production platform and other facilities, all of which increase the carbon footprint of operations. Typically, mature fields have a lower carbon footprint, due to the re-use of existing infrastructure and possibly more efficient extraction methods that have been refined over time, Fig. 3.

Fig. 2. The industry is getting better at executing much-needed well maintenance and production enhancement tasks.

It is not easy to manage the duality of energy sector imperatives: providing a secure and cost-effective power supply amid increasing demand, while also reducing emissions. Oil and gas will continue to be a major part of the world energy mix for the foreseeable future, and the energy that industry brings to the world must be affordable, sustainable and secure. It is possible to tackle this challenge by extending field life, which is critical in a market where mature oil and gas assets must contribute meaningfully and efficiently to the world energy mix.

Considerable value can be extracted from ageing reservoirs. They can deliver shorter cycles, lower costs, and lower carbon production, if the technical, operational and economic challenges can be managed. And that can be accomplished by stepping away from traditional approaches and capitalizing on project management and advanced technologies.

THE POWER OF INTEGRATION

Recognizing that operators benefit from maximizing output from brownfield developments, Baker Hughes built a strategy around mature asset solutions that includes an integrated spectrum of services.

Fig. 3. Intervention increases production with significantly lower CO2 intensity than other methods.

Traditional sourcing methods for intervention services make it difficult to cut costs, because the only avenue open to operators is to negotiate prices for individual services. Setting lower prices for coiled tubing, wireline units, etc. at the front end of an intervention program has value, but beyond the point of contract awards, it is challenging to capture any additional savings. The result is that once a field is in production, there are fewer avenues for cutting costs.

Integration changes the playing field. Historically, an intervention campaign has brought together multiple companies to perform discrete services. Because each company focused on a specific segment of the project, there is limited communication among companies and no common objective. The job eventually is completed, but even in cases where each company captures some cost reductions, there is limited scope for achieving efficiencies.

An integrated approach reimagines the process from start to finish. In a mature asset, challenge complexity multiplies. This requires a solutions approach that pulls together diverse technologies, methodologies and efficiencies from application to design and execution. Instead of an operator connecting products and services in the field, the company can work with one partner that manages a spectrum of services and is incentivized to improve outcomes.  

CHANGING THE MODEL CHANGES THE RESULTS

Once internal integration is established, the next step is to apply a commercial model that promotes efficiency for all team members. With this approach, vendors are no longer focused on an isolated segment of the project but are motivated to work together to improve performance across the value chain. It might seem idealistic, but successful implementations prove that it is effective.

In a recent Well Abandonment Solutions project for a 61-well program, Baker Hughes took an alliance approach, integrating not only its own proprietary products and solutions, but third-party services as well. The process began with alignment of key performance indicators (KPIs), with incentives paid for work completed ahead of schedule. Good performance in the alliance was rewarded with a bonus, while performance below the set KPIs resulted in a malus across the alliance, and all the efficiencies had to be achieved, maintaining safety as a priority. As a result, the team delivered 76 wells in the approximate time allocated for the 61-well program.

Another goal in the systemic approach to mature asset solutions is to reduce the environmental impact of operations by mitigating methane emissions. The process starts with more precisely measuring the emissions during flaring and venting, as well as fugitive releases. The results of a recent full-scale flare combustion study with bp show that accurately measuring emissions not only improves reporting but is a first step to emissions reduction. Employing a proprietary measuring system on 65 flares across seven regions, bp captured real-time data to improve emissions measurement accuracy by 50%. Knowing where to focus and implement early interventions, bp also reduced the amount of methane flared. A recent technological advancement now provides the ability to capture flare gas and use it to generate electrical power, using gas turbines designed to run on different fuel types.

LEVERAGING TECHNOLOGY

Across the board in oil and gas operations, incorporating innovative technologies enables faster, more effective processes and better performance. Bringing advanced technologies together delivers even more value across the five solution themes, Fig. 4. 

Fig. 4 Five themes of mature asset solutions. Image: Baker Hughes

Asset surveillance & intervention. The PRIME technology platform elevates production by introducing a way to seamlessly integrate data and intervention tools to transform task range and performance. The platform allows for delivery of high-performance tractor conveyance and provides in-well drive section configurability, improving string versatility and optimizing tractor speed. In-well speed control and digital telemetry allow production logging acquisition while using a tractor to permit real-time adjustments to drive performance. In an application in the UAE, this technology executed a multiphase production logging job in a sour environment in a highly deviated well, tractoring more than 14,000 ft at speeds up to 64 ft/min to determine the source of downhole gas ingress.

Riserless light well intervention (RLWI) has also been improved through the application of multiple technologies combining Baker Hughes’ proprietary light well intervention system, e-line, slickline, pressure pumping and filtration product lines. This approach proved its effectiveness in its first integrated solutions campaign offshore Nigeria. One of the keys to the success of this project was the time-saving process of moving the light well intervention (LWI) stack from well to well. Using this approach meant the LWI stack was deployed and remained subsea from March through July and was recovered only once—for transit back to port for demobilization. Applying this LWI approach eliminated 42 hrs per well and saved nearly 13 days on site over the course of the project. The maximum pumping rate achieved on this project was 8 bbl/min., with a tubing head pressure of 2,494 psi and a downhole gauge pressure (DHGP) of 5,227 psi at the maximum pumping rate.

Despite implementing an integrated RLWI program of this sort for the first time, the team executed eight subsea well-to-well transfers over 143 days (totaling 3,432 hours) with no incidents or accidents and with no harm to the environment. These results led the operator to expand the scope of work from a three-well to an eight-well campaign to capture optimal value from the well intervention program.

A similar approach was followed in a two-well RLWI campaign in the Lower Congo basin. Collaborating with a major operator, the engineering team employed the company’s proprietary 7.0 RLWI system, pressure pumping, and wireline services to install a water shut-off plug to reduce water cut and boost oil production from the subsea asset. The successful completion of these projects underscores the value of RLWI as a cost-effective option and shows that it is possible to achieve greater operating efficiency while maintaining a lower spread rate. This results in a much lower cost per well, compared to interventions using a traditional mobile offshore drilling unit.

PRODUCTION OPTIMIZATION

Production technology deployments utilizing stimulation in carbonates have been done for decades in the industry. These technologies have evolved from using raw HCl systems to gelled acid systems to emulsified acid systems. Every technology development has tried to emulate the dissolving power, friction pressure, site handling ease and formation damage reduction properties of HCl while controlling the retardation of the acid to meet reservoir productivity needs by enhancing wormhole propagation and reducing face dissolution.

Though both gelled acid and emulsified acid systems have suitable applications, they have some limitations in terms of friction pressure, post-job regain permeability, and site handling ease. Baker Hughes Sta-Live Extreme system was developed as a single-phase acid system for easy onsite handling, which delivers on high dissolving power comparable to HCl systems, gives control, and maximizes formation reach through capability to retard, while low viscosities keep low friction pressures and no formation damage.

In an application in the UAE, Sta-Live Extreme was deployed in a dolomite formation with temperatures ranging >275 °F on an ICD-completed, 5,200-ft horizontal well. The well was previously stimulated by the operator with no production increment. The single-phase acid system eliminated the need for diesel phase, reduced 16 hrs of mixing time and was pumped at 20 bbls/min. Sta-Live Extreme acid system increased oil production by 1,000 bopd in this high-temp dolomite formation, where previous stimulation technologies were rendered unsuccessful.

SAND, WATER & GAS MANAGEMENT

While well intervention can yield positive results, it is not always necessary to enter the well. A recently applied pumping solution allowed wells to not only produce less water with less energy, but to produce more oil and gas without well intervention. The Aquacut Plus technology targeted water production reduction and was combined with stimulation to improve well productivity. This technology allows a strong ionic bond to be formed with the formation rock. It cuts water production, lowers lifting costs and also reduces CO₂ emissions associated with treatment processes and disposal of unwanted water. This solution was used on 30 wells in Colombia, decreasing produced water by as much as 900 bpd. When combined with stimulation applications in the wells, this technology improved hydrocarbon production 43%, with the performance sustained for more than two years following the treatment.

Unlocking bypassed resources. When it comes to extending asset life and tapping into bypassed reserves, integrated coiled tubing drilling has been proven as a cost-effective method to perform well re-entry and multi-lateral drilling, especially in live producing wells. The company recently successfully drilled underbalanced a 4,040-ft lateral in a single run, surpassing its previous record of 4,017 ft, all while maintaining zero unproductive time.

The success of this project was driven by a combination of optimized drilling practices, impactful project management, and the latest advances in CoilTrak™ , a coiled tubing drilling BHA, in combination with USMPR (ultra-slimhole resistivity service). It provided real-time monitoring and data-driven optimization, and turbine-based execution, ensuring sustained drilling performance in extended-reach applications.

Well abandonment. Innovation and technology are the needed ingredients to bring efficiency, simplicity and safety to the next level for well abandonment. Enter the Terminator™ vessel-deployed wellhead cutting system. With a much smaller footprint than alternative wellhead severance solutions, it can operate from a smaller vessel. It requires only two people to operate instead of the usual six-to-eight-person team and burns less fuel than traditional systems. When this solution was deployed on the Norwegian Continental Shelf from a small vessel to cut and remove a wellhead on an abandoned well, the cut took only 35 min., and the operation was completed in 2.5 hrs from tool deployment to recovery.

The potential impact these technologies will have on well productivity, efficiency and cost savings is significant, and the value generated will continue to increase, as more advanced tools are introduced and integrated.

EARLY ADOPTERS LEAD THE WAY

Some operators already are seeing the benefits of integration and rely on a technology partner, who will provide integrated solutions for their intervention or well abandonment operations to bring new levels of efficiency and productivity, so that they can focus their own resources where they can maximize value. 

Recently, Equinor and Baker Hughes signed a multi-year framework agreement for the company to manage every phase of P&A and optimize operations to meet Equinor’s well abandonment goals. To manage the project, Baker Hughes will establish a P&A Center of Excellence in Bergen and Stavanger. This hub of expertise will include project managers and engineers and will centralize P&A activities in the North Sea and ensure that the most economical, reliable solutions are implemented to responsibly abandon each well while maximizing efficiencies.

Further east in the UAE, the company will provide integrated coiled-tubing drilling services for Dubai Petroleum Establishment’s Margham gas storage project on behalf of Dubai Supply Authority. The project will provide stability to Dubai’s energy supply by strengthening the system’s ability to switch between natural gas and solar power. It brings together expertise in integration of coiled tubing drilling, underbalanced drilling and the company’s coiled tubing bottomhole assembly system. This makes it possible to more effectively navigate the subsurface environment during horizontal drilling to maximize reservoir contact, which is crucial for underground gas storage.

Finally, in Brazil, a range of solutions will be deployed to help increase value across multiple offshore mature assets owned by Petrobras. The operator awarded three major integrated contracts in 2024 for flexible pipe systems, well construction services, workovers, and plugging and abandonment that will employ the technology portfolio at scale on multiple assets on multi-year projects.

The first project encompasses wireline, coiled tubing, cementing, tubular running, wellbore intervention, fishing and geosciences services to enhance production across all the operator’s fields offshore Brazil.

The second project, which began with the supply of water and gas manifolds, turbomachinery, turbogenerators, motocompressors and more than 240 km of flexible pipe for three rigs working on Buzios field, will also include drilling services, drill bits, wellbore cleanup, remedial tools and fluids.

The third project includes providing 77 km of flexible pipes, risers and flowlines for hydrocarbon production and associated gas and water injection to address the stress-induced corrosion cracking from CO₂ that is common in pre-salt fields where CO₂ concentrations are high. The flexible pipes provided for this project have a proven record of handling this challenge, offering best-in-class solutions at scale. These systems are crucial for managing the production and injection processes in mature fields, especially those with challenging conditions like high CO₂ concentrations.

THE SKY IS THE LIMIT

Innovative management of mature assets offers a unique opportunity at this time in the history of energy, when drilling new projects can take several years. Unleashing the power of integration from the subsurface to the surface requires new commercial models that create win-win outcomes, eliminate silos and create optionality, enabling every barrel of oil to be produced more sustainably, more cost-effectively and more reliably.

The potential to extend this approach to ensure that mature assets remain a viable part of the global energy mix is limitless. Although projects to date have been localized, it is evident that this approach can be scaled to the field level for even better results.

Ongoing investment to expand the number of integrated services and disseminate the new commercial model could change the face of operations, delivering safety and ESG gains, as well as time and cost-savings.

GUILLAUME FAUCHILLE is Director, Mature Assets Solutions, at Baker Hughes, a position that he has held since September 2023. As such, he leads the Mature Assets Solutions Team for Baker Hughes’ Oilfield Services & Equipment (OFSE) operating segment. In that role, Mr. Fauchille organizes the strategy and execution of this new initiative for the company, in alignment with regions and business segments. The team delivers comprehensive solutions that extend production of mature fields, reduce the CO₂ footprint per barrel, and lower asset retirement costs. Before his current role, Mr. Fauchille spent 17 years, eight months with Baker Hughes in positions of growing responsibility, beginning in January 2006. In 2004, he graduated with a Master’s degree in civil engineering from ESTP - Grande école d'ingénieurs de la construction in Cachan, Île-de-France, followed by earning a Master’s degree in civil engineering from Texas A&M University in 2005. He also acquired a Global Executive MBA from the INSEAD business school in 2021.