The Reservoir Characterization Group brings together domain experts from multiple petrotechnical disciplines. Enabled by Schlumberger technology and reservoir workflows, these experts help determine and model reservoir properties for our customers. Seismic surveys are essential for this work because they provide the only measurement made at the reservoir scale for both the creation and refinement of reservoir models that decrease risk throughout the development planning and production management phases of the reservoir.

To significantly advance the quality of marine seismic data, Schlumberger developed the Q-Marine* point-receiver marine seismic system and the Q-Seabed* multicomponent seabed seismic system. We have evolved offshore seismic surveys even further with IsoMetrix* marine seismic technology, which provides the most detailed imaging of the subsurface, from seabed to reservoir in every direction. These detailed images help to reduce risk and uncertainty during field development planning.

Yet before the field development plan can unfold, the large-scale view of the field must transition to a finer view, at the wellbore scale. To achieve this, our advanced wireline logging portfolio provides customers with a more complete understanding of complex reservoirs. For more than a decade, formation properties have been measured by the Scanner* rock and fluid characterization services family, which delivers a broad array of measurements and analysis—from water volume, salinity, and rock texture to fluid saturation, typing, and producibility. Given its measurement reliability, wireline technology even has applications beyond the Earth’s subsurface. For example, NASA evaluated the performance of Litho Scanner* high-definition spectroscopy service as highly effective in accurately measuring the bulk elemental composition of rocks toward support of a future Venus lander mission proposal.

Well logging is still one of our greatest strengths. It has evolved into a series of more than 100 different services. One of the most recent is Quanta Geo* photorealistic reservoir geology service, which extends the generation of wellbore images that accurately represent formation geology to wells drilled with oil-base mud, where conventional imaging tools cannot fully function. Quanta Geo service provides information about structural and sedimentological features, helping to reveal the best methods to release hydrocarbons from the rock pores and how we can make them flow into the well.

By integrating geological and geophysical models with dynamic well test data, GeoTesting* geology-based well test design and interpretation services maximize the value of well tests. A plug-in for the Petrel* E&P software platform, GeoTesting services can improve characterization accuracy for the geologically complex reservoirs that make up a greater proportion of today’s oil and gas production.

Reservoir characterization must thoroughly evaluate downhole risks. This evaluation begins at the individual wellbore environment as customers bring together all available data into the Techlog* wellbore software platform for analysis and validation. The answer products can then be seamlessly imported into a shared earth environment using the Petrel software platform, enabling petrotechnical experts to understand and characterize the geology surrounding the wellbore, thus improving hydrocarbon recovery.

These software platforms are complemented by powerful physics engines, such as the INTERSECT* high-resolution reservoir simulator for quick and accurate simulation of reservoir behavior over time and OLGA* dynamic multiphase flow simulator for modeling multiphase transient flow within the production system. The engines are used to optimize field development plans and facilities design as well as enable superior asset life cycle management. Schlumberger software builds on more than 30 years of research and engineering (R&E) investment. This investment incorporates deep domain knowledge, supported by the industry’s largest team of petrotechnical experts, and the latest software development practices and digital technology applications. More than 3,500 companies around the globe use our software to achieve their reservoir simulation goals.

Our investment in science and knowledge together with our expertise in information systems is fueling the digital enablement of reservoir characterization to create a digital representation of the subsurface that leverages all available information in the planning, execution, and optimization of E&P operations. We are committed to continuing the technology leadership that this demands by increasing collaboration and integration via cloud-native solutions based on both public and private cloud infrastructures. With the support of our Software Technology Innovation Center in Silicon Valley, we are able to partner with technology industry leaders and quickly appraise emerging digital technology, validate its value for our industry, and adopt it for our technology development and offerings.

Following the development of understanding through reservoir characterization, the next step in the pore to pipeline journey is well construction, from bottomhole drilling assemblies incorporating bits and drilling tools to fluid systems and cementing.

To improve drilling performance, we have integrated the entire drilling system—the bottomhole assembly, drilling fluid, drillstring, and surface equipment—with a drilling workflow that uses data from all drilling system technologies. The acquisitions of Smith International and Geoservices in 2010 were instrumental in enabling Schlumberger to achieve this level of integration.

There are three key objectives of the drilling performance workflow. The first is increasing overall drilling efficiency, which is a function of the rate of penetration and the overall time actually spent drilling. Drilling efficiency—spanning improved rock cuttings extraction, lower cost, and a smaller environmental footprint—is critical for the economic recovery of hydrocarbons. To meet this challenge, our PowerDrive* rotary steerable systems family helps steer wells in a wide variety of environments, from ultrahigh temperatures of 392 degF to wells with highly abrasive rocks. During the last decade, PowerDrive rotary steerable systems have drilled more than 200 million ft in wells from vertical to horizontal.

Drilling performance, including improvements in the rate of penetration, has been further enhanced by new developments in drillbit cutters that operate in three dimensions. For example, AxeBlade* ridged diamond element bit technology employs a ridge-shaped geometry that cuts rock in a new way by combining the shearing action of a conventional polycrystalline diamond compact (PDC) cutter with the crushing action of a tungsten carbide insert.

Another important aspect for drilling efficiency is the fluid, or mud, used to lubricate the bit, transport cuttings from the bottom of the wellbore to the surface, control pressure to prevent unwanted fluids from entering the well, and maintain wellbore stability. Drilling mud effectively reduces the torque, drag, and dispersion that can slow the drill bit’s rate of penetration by using oil, water, or a synthetic fluid as a base. However, in general, using an oilbase mud for higher performance adds additional costs for the required transport and disposal of the resulting waste. The cost-effective solution is our new HydraGlyde* high-performance water-base drilling system, which completely eliminates the waste and disposal costs while delivering a rate of penetration comparable to that of oil-base mud.

The second objective of the drilling performance workflow is precise well placement and formation evaluation to maximize production and provide quantitative reservoir characterization. This requires the acquisition and interpretation of a combination of surface and downhole measurements that are used to guide, or “geosteer,” the drill bit and enhance reservoir characterization. Accurate geosteering depends on real-time data from logging- and measurements-while-drilling technologies. GeoSphere* reservoir mapping-while-drilling service uses deep, directional electromagnetic measurements to reveal subsurface bedding and fluid contact details more than 100 ft from the wellbore. These measurements also help to refine the reservoir’s boundaries for maximizing reservoir exposure.

The third drilling performance workflow objective is wellbore evaluation and assurance, defined as protecting the integrity of the well throughout its productive life. Our leadership positions in petrotechnical skills, workflow processes, and subsurface engineering help our customers efficiently evaluate the cement placement to determine wellbore assurance.

Now that Cameron has joined Schlumberger, our well construction portfolio has expanded to include pressure control and topside drilling equipment and support services to shipyards, drilling contractors, E&P operators, and rental tool companies. This expanded set of products and services, which offers a new market for Schlumberger, features Cameron blowout preventers (BOPs), BOP control systems, and marine drilling riser systems. Cameron brought the first BOP to market in 1922 and remains one of the industry’s leading manufacturers and technology providers.

The drilling process yields considerable volumes of data about the efficiency of the process itself and the subsurface environment. Digital technology that can accelerate the learning curve, improve efficiency, and ensure that the relevant information is seamlessly delivered to the right people at the right time is now beginning to change the drilling process.

Once the well has been drilled, the next step in the pore to pipeline journey is completing the well, from setting the casing, liner, and production tubing to perforating and installing monitoring and control systems as well as constructing the wellhead.

Perforations are made in the casing to open the wellbore to flow before stimulation technologies are used to maximize both flow rate and recovery. One technique in particular, hydraulic fracturing, is commonly performed on oil and gas wells in low-permeability reservoirs. This technique pumps engineered fluids at high rates and high pressures into the section to be produced, which creates fractures in the rock. The proppant mixed with the fluids, usually sand or ceramic spheres, keeps the fractures open so the oil and gas can flow to the wellbore. With the move to more oil and gas development in unconventional reservoirs in North America, a number of new technologies have been introduced to improve this process.

Since its deployment in 2010, the HiWAY* flow-channel fracturing technique has increased average well production in unconventional reservoirs by 20% while also reducing proppant use by 40% and water use by 25%. Other advanced Schlumberger technologies, such as BroadBand* unconventional reservoir completion services, further improve economics by ensuring that every fracture system is kept open from tip to wellbore. For example, one application of BroadBand Sequence* fracturing service in a horizontal well in the Wolfcamp Shale in the Midland basin in Texas increased production by 42%.

Unconventional reservoir operations also require efficiency to decrease total well costs. By integrating the CAMShale* fracturing fluid delivery and flowback service with Schlumberger downhole technologies, more streamlined operations can be achieved. In addition, by engaging a multi-skilled workforce using Cameron surface equipment, more stages can be completed per day to lower total well costs.

Once a well has been stimulated, artificial lift pumps must be installed because only about 5% of oil and gas wells have enough pressure to flow naturally. Since our 1998 acquisition of Camco International, Schlumberger has established a leadership position in electric submersible pumps (ESP) through continuous development of REDA* ESP systems, the history of which goes back to 1926. Schlumberger ESP systems now have integrated sensors that not only take the measurements necessary to optimize performance but also measure well pressure and temperature. These measurements can signal when pump performance is starting to decline or if the well needs workover operations to maintain production levels.

During its lifetime, a producing well usually requires workover operations to maintain, improve, or restore production through mechanical repair or fluid-based treatment. Workover operations often use coiled tubing systems to save operating costs and reduce health, safety, and environmental risks by avoiding the need to install a rig. ACTive* real-time downhole coiled tubing services offer an advantage by using fiber optics to accurately measure key well parameters, such as real-time pressure and temperature. The data can then be swiftly interpreted to optimize production flow while reservoir treatments are still in progress for completing the workover with only one trip in the wellbore.

Ultimately, the most effective way to avoid workover operations is to install an intelligent completion that incorporates permanent downhole sensors and surface-controlled downhole flow control valves. These sensors and valves enable operators to monitor, evaluate, and manage production or injection in real time without the need for well interventions. The evolving challenges of large-scale developments on land and offshore, as well as the need to maximize reservoir contact, ensure well integrity, and manage uncertainty, were the impetus behind the development of the Manara* production and reservoir management system.

The Manara system is the result of an eight-year collaboration between Saudi Aramco and Schlumberger to develop an intelligent completion system for multizone, multilateral, extended-reach, and extreme reservoir contact wells. Integrating 30 patented technologies, the Manara system realizes permanent, real-time monitoring of downhole pressure, temperature, water cut, and flow rate as well as provides in-lateral flow control of zones. This high-level monitoring enables engineers to make production decisions in hours rather than the typical days or weeks when using conventional completion systems.

With artificial lift systems operating in nearly every well, and the number of intelligent completion systems increasing every year, well and reservoir data are more readily available. Advanced software solutions to manage these intelligent completion systems provide a management tool to increase operational efficiency based on data intelligence that tracks performance, alerts operators about events, and pinpoints problems. At the same time, this management tool cuts through the sheer volume of big data, which can obscure understanding for taking the right action at the right time.

It takes the Avocet* production operations software platform to efficiently and cost-effectively manage production by coupling modeling software and engineering workflows. Designed to handle the complexities of production operations, the Avocet software platform conditions, validates, and stores high-frequency, real-time data for creating a complete picture of field production over time. When operational conditions change, users have the tools to identify the reasons behind production discrepancies and use operational decision making and planning workflows that take into account the economic impact throughout the life of the field.

With the reservoir producing to the surface, the next stage of the pore to pipeline journey concerns the production systems that collect, separate, and treat the production fluids before delivery to the pipeline.

The separation and processing systems that make up the production facilities for a given onshore field are typically designed to not only treat the initial production, which includes varying amounts of gas, oil, and water, but also to accommodate the expected changes in production over time.

The removal and treatment of produced water, for example, requires safe and reliable handling that adheres to international environmental standards and regulations. MYCELX^® RE-GEN advanced water treatment media is used as a primary or secondary treatment method for removing oil and suspended solids without the use of chemicals. Optimizing water treatment is also possible with a 50% smaller footprint using the EPCON Dual* compact flotation unit that simultaneously improves the efficiency with which oil and gas are removed from water. These technologies are only two of our many solutions to help increase operational efficiency while reducing operational cost.

Once crude oil is gathered in tanks, it must be processed to obtain the correct quality level, which can be a time-consuming process with a number of sensitive variables. The NATCO DUAL FREQUENCY* electrostatic treater can be employed to meet crude export regulations by dehydrating and desalting crude oil with better efficiency than any other solution available. This technology reduces operating costs and provides customers with a faster return on investment.

Before crude oil is delivered to a refinery, it is blended to create crude with specific physical properties. Heavy and extraheavy crudes, for example, are blended with lighter crude oils to reduce viscosity, which makes them easier to transport. Crude oil blending systems, part of the Cameron Group, achieve target quality by instantly responding to changes while keeping production costs to a minimum. In one operation, crude oil blending systems were installed in two separate terminals feeding four refineries. The systems were designed to blend a domestic high-wax crude into a flowing pipeline containing imported crude oil without causing wax deposition in the main pipeline. In more than four years of operation, these systems enabled the blending of significantly more waxy crude without deposition, thereby increasing customer revenue by millions of dollars per year.

Pipeline transmission of hydrocarbons depends heavily on the valves used and measurements made along the way. Schlumberger now has the industry’s most complete range of valves and measurement systems for midstream and downstream markets through the acquisition of Cameron, which has more than 60 years of experience in the provision of valves for every environment found around the globe. This expertise also includes the fiscal and custody transfer measurement of large volumes of oil and gas as well as the fully integrated measurement and control systems that enable customers to enhance products and processes in real time.

OneSubsea combines technology and innovation to develop the integrated solutions, processing systems, and control systems that increase production and recovery in subsea developments. These integrated solutions enable optimization of the entire system, from the reservoir to the surface, and include well completions and subsea production systems. Offshore Australia, OneSubsea has developed the world’s first unified control system that spans the boosting system and the subsea architecture, the well completion, and the landing string. This new integrated technology controls all seafloor operations at a lower capital cost per barrel. Furthermore, by accounting for changing conditions during the life of the field, our integrated solution can help our customers reach first oil faster, accelerate production, and increase recovery.

Prior to the creation of OneSubsea, Schlumberger had already established leadership in a few of the distinct parts of complete subsea systems, such as subsea landing string services that reduce risk by overcoming the complexity that deep waters, high pressures, and extreme temperatures place on subsea operations. We also lead the market in subsea multiphase boosting and metering as well as wet gas compression through the 2011 acquisition of Framo Engineering AS, a company that specialized in the business of developing and manufacturing multiphase and subsea pumps and multiphase metering systems. The acquisition followed on the heels of a 14-year collaboration between Framo Engineering and Schlumberger for the development of multiphase metering.

Subsea oil and gas reservoirs present significant challenges owing to their high development cost and the need for complex well designs and advanced subsea architecture requirements. In addition, the technical and commercial limitations of subsea production typically result in recovery rates that are often less than half of those for traditional topside development. Although deepwater reserves account for approximately 10% of global oil reserves, the ability to maximize recovery from every subsea project expands the industry’s options for meeting the world’s increasing demand for energy.

Although as much as 80% of our work is still performed under a standard single-product-line contract in which we price our differentiated technologies separately, we can also provide technical support during the operational phases of a customer’s project. At the simplest level, this begins with our Integrated Services Management (ISM) for which specially trained project managers provide scheduling, planning, and activity coordination for the various Schlumberger product lines involved in any given project.

At a more complex level, our Integrated Drilling Services (IDS) and Integrated Production Services (IPS) offerings provide project management, engineering design, and technical optimization capabilities on contracts where commercial terms provide performance-based compensation to Schlumberger IPS. For IDS contracts, this is typically focused on how fast we can drill each well or how optimally we place it in the reservoir, whereas for IPS the contracts focus on turnkey intervention work or extracting incremental production for individual wells.

The highest level of integration we provide is through our Schlumberger Production Management (SPM) model, in which we take full-field management responsibility using the complete range of Schlumberger products, services, and technical expertise. The general scope of SPM agreements covers developing a subsurface model; creating a field development plan; designing, drilling, and tying a large number of wells into production; and managing the production and associated facilities. The development may require flowlines, gas gathering stations, a central processing plant, and the management of third parties.

The SPM model fills a growing market need between the traditional service company and E&P company business models and generally involves the management of mature asset field redevelopment, greenfield development, or the development of unconventional resources. The longer-term nature of these contracts enables Schlumberger R&E to develop fit-for-purpose technologies and methodologies to maximize operating efficiency, increase productivity, and reduce the environmental footprint.

In terms of risk management, SPM has developed rigorous methodologies and standards to evaluate and manage each opportunity. SPM contracts, where we risk the value of our products and services and, in certain cases, additional cash investments, can reach up to 20 years in duration. With these contracts we are compensated for our work through the value of the production we generate from the field.

The origins of SPM stem from Schlumberger Integrated Project Management (IPM), which since 1995 has provided project management services to customers around the world, including production management services. Worldwide, more than 10,000 wells have been drilled and successfully brought to production—a performance backed by several thousand dedicated oilfield specialists, including engineers and geoscientists specialized in world-class field development technologies. In 2016, we acquired Asset Development and Improvement Limited (ADIL), which complements the asset development capability of SPM, and created a Center of Excellence for asset development for Schlumberger and its customers.

During the past 20 years, we have expanded the size, complexity, and number of SPM projects we undertake to the point that today we comanage approximately 230,000 barrels per day of oil equivalent production.

Production management commercial models are flexible and performance based. Projects are executed under a long-term service contract, and SPM’s compensation is linked to incremental production. The commercial models include production incentives for services, technical alliances with production gain share, comanaged assets remunerated on a tariff per barrel produced, and net profit incentive-based compensation.

One such model involves the rapid development of low-cost gas reserves to LNG. The combination of Schlumberger reservoir knowledge, wellbore technologies, and production management capabilities with Golar LNG Limited’s low-cost floating solution through the OneLNG^SM joint venture is expected to provide gas resource owners faster and lower cost development, thereby increasing the net present value of the resources.

The E&P industry has yet to realize the full potential that data can offer. Putting the right information in the right hands at the right time is critical, and only possible if backed by deep domain expertise. At the operational level, this also requires that the individual technologies deployed in the field attain the highest possible productivity levels. This is enabled by integrated systems based on a digital infrastructure that permits the validation, application, and sharing of critical information. In turn, understanding operational workflows and building greater connections between technical domains can increase efficiency and minimize risk while seeking to overcome the complex challenges of the future.

As the industry begins to recover from the deepest downturn it has seen in more than 30 years, the breadth of the Schlumberger portfolio positions us well in any market. Combining technology with new business models and digital enablement connects our customers to the full potential of the domain expertise and data we can provide at every stage of the pore to pipeline process. With activities in more than 85 countries and employees who represent over 140 nationalities, we offer a truly global approach.