The E&P editors and staff proudly present the winners of the 2013 Special Meritorious Awards for Engineering Innovation, which recognize service and operating companies for excellence and achievement in every segment of the upstream petroleum industry. The following pages spotlight the 10 winners the independent team of judges picked that represent a broad range of disciplines and address a number of problems that pose roadblocks to efficient operations. Winners of each category are products that brought monumental changes in their sectors and represented techniques and technologies that are most likely to improve exploration, drilling, completions, production, field development, HSE, and information technology efficiency and profitability.

This year some of the brightest minds in the industry from service and operating companies entered innovative products and technologies that have now been measured against the world’s best to be distinguished as the most groundbreaking in concept, design, and application.

The awards program recognizes new products and technologies designed by people and companies who understand the need for newer, better, and constantly changing technological innovation to appease an energy-hungry world.

The winners were selected by an expert panel of judges comprising engineers and engineering managers from operating and consulting companies worldwide. Each judge was assigned a category that best called on his or her area of expertise. Judges whose companies have a business interest were excluded from participation. The products chosen by the judges represent the best of a long list of winners.

E&P would like to thank these distinguished judges for their efforts in selecting the winners in this year’s competition.

This year E&P will present the 2013 awards at the Offshore Technology Conference in Houston and the DUG Bakken Conference in Denver.

An entry form for the 2014 Special Meritorious Awards for Engineering Innovation contest is available at . The deadline for entries is Jan. 31, 2014.



Being involved with every stage in multistage well completions is one of the most important advantages an engineer can have in the process. Plug and perf (PNP) techniques enable engineers to analyze and adjust each stage of the process, applying changes and knowledge gained to optimize operations. The first stage of the PNP method, however, can be time-consuming and can require mechanical intervention such as coiled tubing (CT), stickpipe, or a downhole tractor to ensure perforation. Unfortunately, this means the operation could suffer loss of productive time and a spike in operational expenses.

Schlumberger has taken this common issue in PNP operations and provided a solution for operators in its aptly named KickStart pressure-activated rupture disc valve. This tool is used in the first stage of a PNP operation, allowing fracture stimulation without the need for an intervention to perforate the casing, the company said. The valve is run in-hole with the production casing and is spaced in the string such that it aligns with the first stage target formation when the casing is landed and cemented in place. This gives operators the ability to test the casing integrity prior to the fracturing treatment operation so that casing operations can continue without interruption.

Rock formations fracture when their weakest point aligns with maximum stress. The KickStart tool targets that stress point by exposing the formation outside the casing to fracture pressure, making sure that the fracture aligns with the maximum horizontal stress plane. This reduces the probability of a premature screenout of the initial fracture treatment by reducing tortuosity at the fracture initiation point. It accomplishes this after the pumps are activated. Pressure begins building up in the casing until one of two rupture disks breaks at a predetermined pressure. Once the disks break, a sliding sleeve in the tool opens a port exposing almost 360° of the formation.

After this event pumping continues as normal, and a fracture is initiated at the formation’s weakest point. Once the fracture has propagated to its designed height and half-length, PNP operations are initiated for subsequent stages.

In the Eagle Ford shale, where PNP operations are a favorite of operators in more than 75% of 4,000 wells in the area, the KickStart tool offers an advantage for engineers looking to facilitate the process, according to the company. To avoid the use of CT or a wireline tractor when attempting to perforate the bottom stage, this technology was used to complete 14 wells in the area. By eliminating mechanical intervention, it was estimated by the company that approximately US $105,000 per well was saved when perforating the first stage of horizontal Eagle Ford wells. The valve successfully handled large fracture stages of 250,000 lbm of proppant pumped at 65 bbl/min, Schlumberger said. The technology has been implemented in more than 300 wells worldwide.



High temperatures are becoming the norm as companies push drilling operations into deeper and hotter horizons. These high-temperature environments can share a predictable outcome when it comes to sensitive instruments used on the field to measure and drilling fluids: Things begin to wear down; characteristics of drilling fluids are degraded; and companies are left to deal with stuckpipe, barite sag, and well-control situations from irregular boreholes caused by the heat. Once conditions affect the quality of logging measurements, which are particularly susceptible to heat because they are on bottom for extended periods of time, data can be compromised.

RHADIANT, an ultra-high temperature nonaqueous drilling fluid from M-I SWACO, has been lab-tested to above 260°C (500°F). In these high temperatures, the drilling fluid maintained its design characteristics, making it ideal when high-temperature well conditions were encountered. One of three components that comprise the system, the MUL XT emulsifier is used to withstand difficult conditions such as ultra-high bottomhole temperatures. The emulsifier contributes to low fluid loss values and contains no nitrogen-based compounds that can break down and release ammonia at high temperatures.

The second component is the ONETROL HT primary fluid-loss agent, which maintains its stability in temperatures up to and above 260°C. The final component is the ECOTROL HT, which acts as a secondary fluid loss agent that also maintains its stability at extreme temperatures.

RHADIANT resists acid gas contamination, controls equivalent circulating density, improves tripping efficiency, and reduces mud loss and stuckpipe incidents, according to the company. The low gel structure of the RHADIANT system remains nonprogressive even in the presence of low-gravity solids while still minimizing barite sag. Low HP/HT fluid loss and the ability to generate a high-quality filter cake help protect the wellbore and surrounding formation from invasion. In close drilling margins the equivalent circulating density management characteristics of the system reduce hydraulic pressure cycling and surge and swab pressures when pumps are restarted after a trip, according to M-I SWACO. It exhibits gas tolerance to both HS and CO. The RHADI-ANT drilling fluid works well with various synthetic and mineral oil-based fluid chemistries, providing drilling engineers the flexibility they need to meet specific downhole conditions despite the heat.

In the Gulf of Thailand, where extremely high bottom-hole static temperatures are often measured at an excess of 232°C (450°F), operators require a drilling fluid solution that can mitigate the issues that occur when operating in extreme high-temperature environments. One operator expected bottomhole temperatures of 234°C (453°F) in an exploration well deviated to almost 52° and containing quantities of HS and CO. After a conventionally drilled pilot hole the RHADIANT drilling fluid was used to ensure high temperatures would not compromise logging data. According to M-I SWACO, the production zone was drilled using 10.5 lb/gal RHADI-ANT with a base fluid of Sarapar-147. While drilling in the 6-in. production zone, no drilling or lost circulation problems were encountered. According to the company, good hole cleaning was achieved, and even after tripping several times through some tight spots, no stuckpipe was encountered. Within a period of 20 hours three successful logging runs were performed with no reported nonproductive time.



In high-temperature gassy environments common to thermal-recovery heavy oil applications like steam-assisted gravity drainage (SAGD) or steamflooding, rugged electric submersible pump (ESP) systems are conventionally unreliable. Such systems are delicate and cannot handle high bottomhole temperatures, decreasing the chances of early production and increasing the chances of downtime and intervention costs. Components of the ESP subject to mechanical stresses, such as shafts, flanges, bolts, and bearings, can ultimately reduce run life if impaired. To increase the chances of reliability and reduce downtime and intervention costs, Schlumberger designed the REDA HotlineSA3 high-temperature ESP system, which can operate reliably in wells with bottomhole temperatures of up to 250°C (482°F).

The system incorporates an integrated design that extends system run life and the ESP operating envelope, the company said. Its design is specifically for high-temperature gassy environments; for corrosive, abrasive environments; and for wells with poor cooling characteristics.

Unique to the system is the new Integrated Motor configuration, a complete rearrangement of the traditional ESP design. The Integrated Motor function comprises a shaft seal module (SSM), a motor, and a compensator. Conventional systems have a single seal section; the HotlineSA3 ESP features a seal section that is split into two parts. The shaft sealing functions are maintained on top of the motor in the SSM, while the motor oil compensation and pressure equalization functions are moved below the motor. The short shaft sealing sections are stacked on top of the motor to add redundancy and layers of protection, which enhances motor reliability. The shorter SSM increases tolerance to dogleg severity such as that found in SAGD wells. To reduce mechanical stresses, the SSM includes filters for the prevention of damage to seal components and ceramic bearings for high-load capacity to handle abrasives. Because the compensator is located at the bottom of the motor configuration, the pressure equalization and abrasives are isolated. Additionally, all nonmetallic components are able to withstand the new temperature ratings. O-rings, motor insulation, and radial and thrust bearings also were upgraded. In addition to upgrades for high-temperature environments, the Integrated Motor includes a prefilled plug-in concept that can reduce chances of human error during installation, the company said. Because the oil is prefilled at the factory, the need for filling at the well site is eliminated, which also eliminates the risk of getting water/solid impurities and entrained gas into the motor. This can result in ultra-purified motor oil, which enables increased insulation reliability and run life. To prevent fluids from escaping and entering the motor, the plug-in pothead design has a positive pressure system and dual-elastomeric seal.

In an SAGD project in the Athabasca oil sands of Alberta, Canada, a team planned to trial the REDA HotlineSA3 ESP in 55% of the SAGD wells. Because of the high-temperature gassy environment found in this particular application, aquifer pressure had to reach approximately 406 psi, not including a safety margin. One trial well completed with a conventional ESP rated to 218°C (424°F) ran for almost a year until failure. With the HotlineSA3 system lower subcools were achieved as a result of improved heat transfer, increasing emulsion rate. The testing revealed that for the lower-rated ESP systems to stay at or below 218°C, subcools were high, meaning that fluid could not be produced. The new system allowed steam chamber development at elevated temperatures, the company said, improving heat transfer, which in turn mobilized fluid more effectively. The HotlineSA3 ESP also was able to remove fluid as it accumulated, driving the sub-cools lower for higher flow rates.



The drive to reduce costs and improve operating efficiencies continues to be a dominant theme within the E&P sector in general, and the seismic industry in particular. As finding and development costs escalate, there is a growing need for improved seismic technologies that drive down data acquisition costs and increase efficiency without compromising either safety or environmental impact. This need has been the impetus behind the rapidly growing trend to switch from cabled to cableless recording systems. Autonomous recording nodes in particular have a number of significant advantages over traditional cabled and radio telemetry recording systems such as improved operating efficiency and flexibility in design and deployment.

Global Geophysical has created one such system, called the AutoSeis High-Definition Recorder (HDR). With this compact recording technology crews are able to lay out and pick up recording channels much more rapidly using fewer workers and with less vehicular support, both of which lead to reduced HSE risk exposure to the crew. In addition, downtime is reduced since there are no instances of network failures as there are with cabled or radio telemetry systems. Because the recording units are independent from one another, there are no physical or electrical limitations on total channel count nor on how near or far the units can be positioned from each other. As a result, it is much easier to customize 3-D design and deployment where topography, surface access, or landowner restrictions can limit traditional recording systems.

The AutoSeis HDR also benefits the operation by its reduced weight, which improves safety conditions for the crew and increases the number of stations that can be transported. The tool weighs 0.7 lb/single channel station, the lowest weight of any nodal recording system on the market, according to the company. Together with a 20 Amp-hr lithium-ion battery, which is independent from the recording node and can power the unit for more than three weeks, the total weight is approximately 3 lb.

AutoSeis has more than 155 dB of dynamic range and an internal noise floor of only 5 microvolts, which is the best on the market today, the company said. Recording accuracy such as this can help retrieve small signals from under high noise levels, a characteristic that is particularly important for microseismic monitoring. The seismic data on the HDR are recorded in full 32-bit digital format to ensure full resolution is preserved. Though using a global positioning system to discipline the timing on the tool’s internal clock to maintain accuracy is not unique to AutoSeis, the tool is the only node, according to the company, that uses a helical scan antenna originally designed for military use. Another advantage unique to the tool is its full encasement in resin, which prevents environmental intrusion – typically of water – that can result in loss of data or recording failure.

In the Wolfcamp formation, where operators are faced with rugged topography, obtaining seismic data that properly illuminate the target formation is difficult. Traditionally, data have failed to generate the seismic resolution needed to support detailed stratigraphic interpretation and stress field characterization. A survey was conducted to test the value of high-resolution, wide-azimuth, high-fold seismic data in such a setting while tightly controlling the cost of acquisition. The AutoSeis nodal recording system allowed for rapid deployment and retrieval of recording groups thanks to its lightweight design, the company said. More than 1,200 groups per day were laid out and picked up. The seismic crew recorded more than 2 billion traces spanning 920 sq km (355 sq miles) in difficult terrain in approximately five months. Eight times the data effort incremented costs by 58% and resulted in a substantial uplift in the quality of the imaged data, according to the company.



Vertical seismic profiling (VSP) can provide improved lateral and vertical resolution for 3-D imaging compared to its counterpart, surface seismic; however, it is not often used because of several logistical drawbacks. Conventional geophone technology can hinder the acquisition of VSP data. This can be due to well intervention, well integrity risk, high economic cost, limited wellbore coverage, and limited equipment ratings for HP/HT conditions.

Distributed acoustic sensing (DAS), a new application, is offering some answers. The tool leverages the increasing use of fiber optics installed in wells by turning single-mode optical fiber into an array of distributed sensors.

OptaSense has developed the OptaSense DAS system, which works by interrogating a length of standard optical fiber with pulses of highly coherent laser light. According to the company, the system then measures the amount of light returned from tiny scatter points inherently present in the glass along the fiber. The phase and amplitude of the backscattered light is a function of strain on the fiber.

By being able to deploy a fiber-optic cable during the construction of a well or by retrofitting to legacy fibers, well risk, well production downtime, and deployment time are alleviated. Conventional downhole geophones also resulted in limited wellbore coverage, which is eliminated with the DAS technology, the company said.

In HP/HT operations the system is reliable and exceeds typical industry geophone ratings, the company said. Downhole fiber-optic cables currently are rated to a temperature of 300°C (572°F) and pressures up to 40,000 psi.

For a carbon capture and sequestration project aimed to reduce the overall carbon footprint of the Athabasca oil sands development, the OptaSense DAS for VSP was used as part of the measurement-monitoring verification. A series of baseline zero-offset VSPs was acquired to monitor COcontainment. A series of walkaway VSPs monitored the COinjection plume and tube-wave monitoring of casing integrity and completion permeability. The DAS system operated on a single-mode optical fiber deployed behind the casing of the well. The well was inactive during the acquisition. The system was configured to operate 177 levels at 10 m (30 ft) from surface to total depth. A geophone string also was deployed in the well. It was configured with a 7.5-m (25-ft) spacing and moved three times to span the entire well for the zero-offset VSP and with a 10-m configuration over two locations for the walkaway VSP. The DAS system was deployed in a trailer unit, which was located at the edge of the pad, with a single-mode fiber spliced into the in-well fiber. It was then run back to the unit. Results showed a good correlation with both sonic logs and geophone data, which demonstrated that the DAS technology yielded very usable data, the company said. The technology also was easier to deploy and less expensive, according to OptaSense. Because the fiber was permanently installed, it was significantly more repeatable than the three tool settings that the geophone acquisition required. It also acquired data for the entire well with a single shot.



When hydrocarbons are deposited within complex structures at great depth and under deep water, they can be hidden from view beneath dense overburdens. Some reserves are not recoverable due to geological uncertainty. Conventional marine seismic sampling techniques have provided the industry with an effective method of acquiring high volumes of subsurface data offshore. These data have been thus far labeled as “3-D;” however, the parallel lines acquired are coarsely spaced in the crossline direction. WesternGeco calls these conventionally acquired data “2½ -D.” Streamers are typically towed 50 m to 100 m (164 ft to 300 ft) apart. According to the company, these methods do not capture the whole wavefield and are limited in their accuracy when imaging the subsurface.

True 3-D imaging of the subsurface can be provided via a point-receiver multisensor streamer system, which WesternGeco has used in its IsoMetrix marine isometric seismic technology. The tool uses towed streamers to provide a true measurement of 3-D seismic wavefields. According to the company, the technology delivers high-fidelity point-receiver seismic data while overcoming spatial wavenumber bandwidth compromises that have limited previous marine seismic acquisition methods. IsoMetrix provides a continuous measurement of the full upgoing and downgoing notchless seismic wavefield sampled at a 6.25-m by 6.25-m (20.5-ft by 20.5-ft) point-receiver surface grid. This makes the data suitable for use in interpretation and modeling applications such as deep reservoir characterization and 4-D reservoir monitoring. The Nessie-6 point-receiver streamer system incorporates a new generation of towed streamer design, which combines measurements of wavefield pressure and gradient vertically and crossline. Using point-receiver technology that combines hydrophones with calibrated point-receiver microelectromechanical system accelerometers, geologists are able to obtain a direct measurement of the vertical and crossline gradient. This enables unaliased reconstruction of the pressure wave-field between streamers, the company said.

A computer algorithm performs simultaneous spatial reconstruction and receiver deghosting of the seismic pressure wavefield. The algorithm can compute the upgoing and downgoing separated wavefield at any desired position within a spread of streamers, Schlumberger said, contributing to an “unmatched” level of 4-D repeatability.

In the 2011 field trials IsoMetrix achieved a 12:1 crossline reconstruction ratio and produced a 6.25-sq-m (20.5-sq-ft) surface data grid from streamers that were spaced 75 m (246 ft) apart. In January 2013 the seismic vessel WG Vespucci, equipped with 10 full-length streamers, began acquiring seismic data using the IsoMetrix technology for a 3-D survey for Thombo Petroleum. The survey covered a full fold area of 686 sq km (265 sq miles) extending over the A-J1 graben of Block 2B located off the west coast of South Africa. According to the company, the new data will allow Thombo and its partner Afren Plc to evaluate not only the extent of the A-J1 oil discovery but also the many other prospects and leads in the graben that have been identified from existing 2-D data.



With hydraulic fracturing in the spotlight, companies constantly keep the environment and safety of crews and supporting personnel a top priority. On well locations where hydraulic fracturing operations are conducted, the inhalation of silica dust is among one of the risks to the crew. Respirable silica dust is more hazardous than in previous years due to the increased sand volume in the high-rate fracturing operations being conducted in the completion of extreme-depth horizontal wells in various US reservoirs, according to Nabors Completion & Production Services (NCPS). Workers who are in a position to breathe such silica dust on a regular basis are at risk of developing silicosis, a disease in which lung tissue reacts to trapped silica particles. This can cause inflammation and scarring, which reduces the lung’s intake capacity of oxygen. Silica also can cause lung cancer and has been linked to tuberculosis. Since hydraulic fracturing sand can contain up to 99% silica, various studies have shown that fracture crews and other associated personnel may be exposed to this dangerous dust.

In response to this HSE concern, NCPS developed the Nabors silica dust collection system. The unit addresses silica dust emission in three main activities of the fracturing operation. First, dust collection on top of the sand vessel access ports captures fugitive dust during the process of offloading from sand transports. The system is able to capture dust from one to six transports unloading simultaneously. Second, the unit collects dust when sand is transported from sand vessels to the conveyor-belt system. Finally, the unit captures dust when the conveyor belts drop sand into the blender.

In the Marcellus shale NCPS conducted a multistage hydraulic fracturing job on a well site in Pennsylvania. It employed the silica dust collection system on the site to capture fugitive silica emissions. The job required approximately 10 MMlb of various sizes of silica sand. In total, 24 tons of a fine powder dust was collected over the course of the stimulation job. Afterward the dust was sent to a third-party laboratory to be tested and analyzed. A sieve and hydrometer analysis revealed that the percentage of 200-mesh silica was more than 53.75%. According to the company, these submicron particles of 0.1 mm diameter and less are sometimes difficult to detect by the naked eye. Also found were particles as small as 0.001 mm, amounting to nearly 10% by weight of the sample. Particles as small as 0.01 mm comprised the additional 20% by weight of the sample.

A wash sieve analysis showed that 200-mesh and smaller particles accounted for 46.3% of the weight of the sample. Sand sieve sizes of 140-mesh to 200-mesh accounted for almost 42% of the sample weight.

Finally, almost 24% of the sample weight revealed 60-mesh to 140-mesh sand. This indicated how to adjust the flow rate of the silica dust collection system. Sand in this range can settle back into the conveying system if allowed the time. This indicated that the vacuum’s area of influence should not be directed in the same paths across the stimulation equipment.

NCPS noted that while the dust collection system was operational, filter life on fracturing equipment also was greatly extended.



The logistics of sand and space in hydraulic fracturing operations can become incredibly intricate, especially with HSE objectives in mind. Conventional sand handling processes use horizontal storage bins that do not do much to aid HSE objectives and require more power to transport. They also take up a great amount of space in operations where space can be very precious to operators. A simple fix would have been to save space by simply making vertical storage bins for sand operations. Halliburton went a bit further.

Vertical structures can take advantage of gravity, which lowers the total power requirements. The company took advantage of the height that the new vertical bins give to provide solar panels, which generate electricity for operating the bins. Rethinking the way operators can store sand resulted in the SandCastle vertical storage bins.

In addition, the storage bins use a weighing scale to measure the stored material, which can improve the accuracy of the proppant, the company said. A stabilization system is used to ensure the bins are stable when exposed to wind when empty and when being loaded.

The bins do not require diesel power packs, which can decrease emissions, noise, maintenance, and total site diesel consumption. Doing away with conveyor systems can reduce the likelihood of hydraulic oil spills, greatly reduces dusting, improves proppant delivery reliability, and can lower the chance of injuries, according to the company.

Additional proppant storage helps improve productivity in horizontal well completions and can translate to less nonproductive time for the operator. The integral weighing system on these bins improves service quality through very accurate proppant measurements throughout the course of a stimulation treatment. Knowing and controlling exactly how much proppant is placed into the reservoir is a key metric in determining the success of a fracturing treatment and improving the performance of a well over the long term, the company said. In addition, the volume and speed of filling the SandCastle bins can reduce the charges incurred by the operator for sand trucks waiting to unload, which can be significant considering the number of trucks required to transport proppant for large fracturing treatments.

An independent energy company operating in Pinedale, Wyo., wanted to complete its horizontal wells in a shorter timeframe. After adding the SandCastle bins, nonproductive time associated with proppant equipment dropped to negligible levels. For example, only 10 hours of nonproductive time occurred in eight months. The operational efficiency gain is evidenced by demurrage charges for proppant delivery trucks waiting to unload having been reduced by approximately 30% since the use of the vertical bins began. In addition, Halliburton said, emissions and noise were completely eliminated, while dusting at the well site was proportionately reduced.

In the Permian basin SandCastle bins have been deployed to provide both economic and HSE benefits, the company said. The smaller footprint allows the sand trucks easier and closer access, thus requiring shorter hoses for moving the sand from the trucks to the bins. This results in a time savings of 15 minutes to more than an hour when compared to the time required for loading legacy sand storage equipment, according to the case study.



Designed for completing massive productive intervals but benefiting most completion applications, the Schlumberger INsidr perforating shock and debris reduction technology reduces risk in two ways. First, it mitigates the dynamic shock of a massive pressure surge caused when a large-diameter long gun system is detonated in a high hydrostatic pressure environment. Second, it acts to contain up to 85% of the debris-causing material inside the gun carrier.

The INsidr gun system uses a proprietary volume reduction sleeve specifically designed to reduce the void space inside the gun carrier to mitigate the severe dynamic shock caused when a gun is fired under high-pressure conditions greater than 20,000 psi. In addition to reducing the shock by filling in gun void space, the volume reduction sleeve prevents charge casing disintegration, the chief contributor to perforation debris in conventional guns, Schlumberger said.

In high-pressure wells guns with INsidr technology produce much lower gun-shock loads than standard guns. The charge casings remain practically intact inside the gun carriers, dramatically reducing the debris that could plug perforation tunnels or impede installation of the completion.

The ultra-deepwater wells in the Gulf of Mexico’s (GoM) Lower Tertiary play extend deeply to reach target formations. Many operators are contemplating drilling wells to depths of 9,144 m (30,000 ft). Each pipe trip into such a well constitutes a risk. The introduction of guns with INsidr technology has allowed operators to shoot all production zones in a single trip with high-performance, high shot-density charges without jeopardizing well integrity or creating unacceptable volumes of debris, the company said.

Schlumberger uses its PurePlanner software to anticipate peak dynamic loading on well components when the guns fire. Once peak loads are identified, the software is used as a design tool to modify the gun string and bottomhole assembly to mitigate shock to manageable levels, the company said. Prejob modeling results indicated that the maximum dynamic underbalance at the top of the gun string would be 35% less with INsidr technology. This reduction in peak underbalance corresponded to a 230,000 lb/ft reduction in the maximum tensile load on the tubing-conveyed perforation packer.

In 2012 in the GoM an operator successfully perforated a well in more than 2,133 m (7,000 ft) of water. Four zones were simultaneously perforated using Schlumberger 7-in. 18 shot/ft high shot-density guns with INsidr technology. Hydrostatic pressure was greater than 20,000 psi at the bottom gun, which reached a depth exceeding 8,534 m (28,000 ft), breaking world records for large-diameter perforating guns, according to Schlumberger. The total gun string spanned nearly 396 m (1,300 ft) – a record length for large-diameter guns at such extreme depth and pressure. The net perforated interval was approximately 244 m (800 ft), and almost 14,000 big-hole shaped charges were simultaneously fired. Two explosively initiated vertical shock absorbers placed directly above the guns provided additional protection for the upper string and packer, the company said. High-speed pressure data recorded at the firing heads matched well with the predicted pressure response, verifying the accuracy of the simulation model.

The INsidr technology’s debut job in the Petrobras Cascade/Chinook ultra-deepwater development demonstrated the tool’s ability to shoot all zones on a single trip with a 67% reduction in rig time, saving an estimated US $14.7 million per well.



Being able to predict and identify downhole conditions would reduce catastrophic well events and nonproductive time (NPT). To achieve this, the behavior of mechanical, hydraulic, and thermodynamic models must be analyzed and understood. Key drilling variables such as wellbore pressure profiles, hook load, surface torque, cuttings transport, tank volumes, and standpipe pressure should all be calculated. It is best when these data are calculated in real time and even better when all data are integrated into one model.

DrillScene by Sekal aims to minimize risk and costs by providing a tool that can help users manage, understand, monitor, and optimize a drilling program in real time, the company said. According to Sekal, it is the only pure physics-based tool in the commercial marketplace capable of predicting and identifying downhole conditions that could subsequently lead to NPT or to catastrophes. The company said the tool has repeatedly identified the precursor symptoms of deteriorating downhole conditions hours or even days prior to the onset of drilling problems in both field trials and during live drilling operations. Advance notification such as this enables proactive changes to the well program, mitigating the precursor symptoms and preventing potential drilling issues. The system links the transient behavior of the mechanical, hydraulic, and thermodynamic models into one integrated model. It calibrates drilling variables such as wellbore pressure profiles, surface torque, hook load, tank volumes, cuttings transport, and standpipe pressure in real time. It then compares the modeled data with the real-time measurements recorded at the rig site. This enables DrillScene to quickly identify whether changing conditions are normal behavior or if they are symptoms or conditions that require corrective action.

In 2012 Total Norge AS’s offshore Garantiana well 34/6-2 used the system during drilling operations for monitoring and support for key well sections. Specifically, Total used the tool to closely monitor the equivalent circulating density (ECD) and the effectiveness of hydraulic hole cleaning and to observe any signs of fluid influx into the well. A potential consequence of inadequate hole cleaning would be for the ECD to rise and exceed the fracture gradient within the wellbore. During drilling operations, the pressure-while-drilling (PWD) tool was inactive due to flow rates in the well-bore being below the tool data transmission activation flow rate. An earlier modeled ECD profile in the well-bore and the actual measured PWD values from the pressure sensors within the bottomhole assembly provided support and confidence in the physics-based modeling of the ECD, the company said. Rather than tripping the bottomhole assembly to the surface, the drilling team elected to continue the drilling operation, relying solely on the tool’s ECD modeling to manage and monitor the pore pressure and fracture gradient limits. This saved the team one rig day of costs. During the operation, key well events such as hole cleaning issues, ECD limits, fluid influx, and others were noted and captured, enabling drilling analysts to propose drilling performance improvements to enhance the efficiency of the drilling operation. In addition, the tool provided a real-time warning of the modeled full well-bore ECD approaching the pore pressure and fracture gradient limit within a key zone located some distance above the PWD tool. It also proved modeled values for ECD in both the coring run and the running casing where real-time downhole ECD measurements from the PWD were not available.



Surfactant is important to use after a hydraulic fracturing operation to remove the fracturing fluid. This ensures that oil or gas can flow more freely into and through the fractures. Some surfactants such as proppant or formation materials tend to spend themselves quickly by plating out onto surfaces. Surfactant is needed at the leading edge of the fracture fluid as the fracture grows, so this means that the surfactant is not available where it is needed most.

Flotek has created the Complex nano-Fluid product that comprises nanodroplets of around 10 nanometers to 20 nanometers in diameter. Its small size allows the droplets to enter very small porethroats for enhanced mobility into the formation. Additionally, the nanophysics cause the small droplets to remain intact to mobilize at the fluid interfaces rather than plate out. This ensures the surfactant contained on the nanoparticle is always available where needed, according to Flotek. CESI’s CnF chemistry, via its nanoparticle mechanism, reduces surface tension and interfacial tension between the rock and injected fluids. The additive reduces capillary pressure and minimizes capillary end effects associated with well-bores and fractures in low-permeability reservoirs by about 50%, according to the company. Additionally, it minimizes fluid absorption on shales and fluid leak-off into the formation. The products are biodegradable, natural, renewable, and eminently sustainable.



The Mangrove reservoir-centric stimulation design software from Schlumberger is a plug-in for the company’s Petrel E&P software platform that enables an integrated stimulation design and evaluation workflow. The Mangrove software pinpoints the sweet spots for perforation cluster placement and hydraulic fracture staging. According to the company, this automated process has improved ultimate recovery by more than 50% while reducing design time by one-eighth. Schlumberger said the system has the ability to model complex fractures typical in unconventional reservoirs. Underlying numerical solutions capture the interaction between induced fractures with the natural fractures, accounting for varying geomechanical and petrophysical properties. Mangrove provides an end-to-end seamless process enabled on a single platform for designing and evaluating from both technical and business perspectives, the company said. In one operation in the Marcellus shale the tool was used to identify sweet spots and stimulate the entire well. The technology resulted in 25% more stimulated volume and 35% higher initial gas flow rates than in the offset well.



The HiWAY flow-channel hydraulic fracturing technique from Schlumberger improves the deliverability of hydrocarbons from the reservoir to the wellbore by creating channels within the propped fracture. These open channels offer less resistance to the flow of oil and gas, leading to enhanced productivity. Proppant requirements are reduced by up to 47% since the operation does not aim at filling all the space within the fractures with prop-pant. The channels are created within the proppant pack through a patented technique that combines a special pumping procedure, perforation scheme, and fiber technology. Fracture performance becomes independent of retained proppant pack conductivity. Also, the open channels extend from the near-wellbore area to the tip of the fracture, significantly increasing the effective fracture length. Extensive field tests of the flow-channel hydraulic fracturing technique have shown increased flowback rates, improved polymer recoveries, decreased risk of screenout and proppant flowback, and substantial gains in production. Over a two-year period wells treated with the HiWAY service have proven stability of flow channels and sustained hydrocarbon production, the company said. In one case study, wells using HiWAY used 47% less proppant and 26% less water than two offset wells.