Maximize the returns from your infill well investments by harnessing the power of fit-for-purpose technologies and digital workflows
Infill drilling accounts for more than 60% of the new wells drilled in North America, making it more important than ever to follow a consistent and holistic process of planning, designing, constructing, completing, and producing them.
In most US unconventional basins, operators start development by drilling the minimum number of wells needed to hold their acreage. These initial wells are sometimes called parent wells. Operators then start drilling infill wells, also called child wells. When the child well stimulation operation communicates with a parent well, the result is parent-child well interference or a frac hit.
Frac hits can have positive, negative, or neutral effects on parent well production. In addition, infill well production varies with distance from the parent, time elapsed since the parent began producing, and other factors. Rapid production declines can also occur in parent and child wells after infill well stimulation.
Learn about minimizing losses during well shut-in and restart operations.
Download the webinarThe point of infill drilling is to replace reserves as parent well production declines. But the parent well’s production depletes the reservoir, and the reduced reservoir pressure tends to reduce formation stresses, attracting new hydraulic fractures from nearby infill wells.
If a new well is too close to the parent well, its fractures will grow asymmetrically toward the lower stress, creating a drainage area that largely overlaps the area already depleted by the parent well. Thus, the child well’s initial production will be markedly lower than that of the parent well, and it will decline faster.
Differences in experiences by play exacerbate the challenge of optimizing the field and individual well designs.
In case you missed it: Learn about best practices for developing and extending unconventional fields with infill wells.
Watch the webcastFactors for success in North Dakota, US, and Saskatchewan and Manitoba, Canada.
Petro-Hunt uncovers opportunities for drilling risk mitigation and well design innovation.
Recently developed conveyance and acquisition system greatly reduces costs and risks.
Comprehensive assessment and clear recommendations for challenging partially depleted stacked pay interval.
Case studies from the Bakken, carefully considering all the physics, rock, and fluid interaction in the subsurface strata.
High-pressure injector technology and large-particle diverter pills reduce job time.
Fracturing service stimulates uncemented 1,822-ft section, treats 17% of lateral length, Williston Basin.
Optimized stimulation services boost parent well production by 150% and infill well average by 66% over the parent, North Dakota.
New sequenced fracturing technique further increases reservoir contact, Williston Basin.
Completion techniques in the Middle Bakken formation have evolved over the years, with cemented Plug & Perf becoming the most common technique in recent years. It relies on stimulation of multiple clusters of perforations, normally 3-5, at one time.
Fracture geometry control reduced frac hits as confirmed by high-frequency pressure monitoring.
Increase proppant placement around infill wells and prevents fracture interference.
Design methodology, execution details, and production results from Williston Basin.
The increasing trend of drilling infill wells (more than 60% of new wells in 2017) comes with the significant risk of well interference.
Engineered REDA Maximus ESP system manages steep production decline to achieve 82% drawdown in the Bakken Shale, North Dakota.
Customer experiences continuous production down to 200 bbl/d using one ESP system.
Customer increases production while avoiding ESP replacement and related costs.
Factors for success in the Midland Basin and Delaware Basin of West Texas and southern New Mexico.
Workflow combines high-resolution sonic and resistivity imaging for optimizing completion design and hydraulic fracturing.
Overcome casing size limitations and determine ideal targets based on geomechanical properties.
Mangrove stimulation design uses log measurements to intelligently place perforation clusters in optimal intervals of high-pressure shale play.
MDT tester, fracture injection tests, and sonic logs confirm minimum horizontal stress.
TOC from Litho Scanner spectroscopy service and NMR pore-size distribution identify the sweet spot for optimal horizontal landing. point, Bone Spring Sand.
The impact of different well spacing configurations on well interference and production performance.
How changes in well spacing and proppant volume will impact new infill well performance.
Successful application of seismic data and DFN for modeling hydraulic fractures in unconventional reservoirs.
Secondary porosity features and natural fractures obtained across dynamic resistivity range.
No rig required for obtaining a complete dataset in a horizontal well by tractor conveyance of Pulsar spectroscopy service and ThruBit Dipole acoustic service.
Combining modeling, rock-fluid compatibility testing, and efficient OneStim services reduces stimulation costs, Permian Basin.
Applying a multidisciplinary integrated workflow to a horizontal well to model complex hydraulic fractures and production.
Cement-conveyed frac performance technology efficiently mitigates hole-cleaning challenges by altering mud mobility—without special equipment or cement designs.
Minimizing interstage communication during hydraulic fracturing treatment results in higher normalized 3-month cumulative production.
Fulcrum technology changes rheology in cement mud channels to prevent fluid movement.
Preliminary results of field testing of new cement system that improves zonal isolation.
Composite fracturing fluid maximizes wellbore contact in highly laminated and pressured unconventional reservoir in Permian basin, southern USA.
Better proppant transport and increased vertical conductivity make better wells in the Wolfcamp Shale, Permian basin.
During the industry downturn, operators tend to fine-tune efficiencies to drive down costs.
Proactive approach of designing, monitoring, and responding to shale wells.
AvantGuard services guides poststimulation operations, Permian Basin.
The best way to manage solids production is by optimizing the initial completion.
Real-time surveillance service monitors downhole pump performance and enables improved production and pump uptime in two unconventional fields.
Surveillance and optimization avert 1,800 bbl of deferred oil production and 800 hours of field service in just 3 months.
Established operators in the Permian Basin have been producing from legacy mature fields and formations for many years with vertical wells, but the focus has shifted to aggressive growth in new unconventional resource plays. With this shift, a majority of the players have transitioned their programs to horizontal wellbores with multistage completions.
Factors for success in South Texas.
FMI microimager, Sonic Scanner platform Stoneley data, and CMR-Plus magnetic resonance in one trip.
Open- and cased hole logging used to optimize positioning of fracture stages and perforation clusters for more efficient production from horizontal wells.
One of industry’s greatest challenges in unconventional plays–especially at today’s oil prices–lies in designing completions that increase production significantly while simultaneously controlling costs.
Combining ThruBit services, Kinetix software, and BroadBand Sequence service increases production for Lonestar Resources in the Eagle Ford Shale.
Operator reduces completion costs by 11% with integrated stimulation design and modeling.
Integrated workflow helps optimize infill drilling in drill-to-hold leases by minimizing the occurrence of fracture hits and well interference.
Value of acquiring petrophysical data in the lateral section and its application to completion optimization.
Results of the study can change the way unconventional resources are developed.
Completion design for unconventional shale plays in North America is a topic of high current interest. Although the practice of stimulating shale horizontal wells with large slickwater treatments is slowly changing to the use of Hybrid/Crosslink treatments in certain plays, little has changed with the method of completion design itself.
In multistage fracturing of unconventional formations, such as the Eagle Ford shale, wells are traditionally stimulated by fracturing several perforation clusters at once. While the technique is operationally efficient, there is evidence from production logs, microseismic monitoring and other measurements that several of the clusters produce below expectations or do not produce at all.
As the oil & gas industry enters into next phase of unconventional reservoir development, many new in-fill wells will be drilled in various shale oil and gas plays in North America. A detailed evaluation to devise an engineered approach for stimulating and completing these wells is critical to maximizing productivity.
Fracturing service significantly increases stimulation effectiveness compared with conventional plug-and-perf technique.
Schlumberger restimulates well, accesses new rock, increases reserves, and increases flowing pressure by 4,750 psi.
Advanced sequenced fracturing service doubles oil and gas production rates while quadrupling flowing pressure, Eagle Ford Shale.
Fracturing service significantly enhances operational efficiency and reduces the number of bridge plugs required by 68%.
Aggressive engineered stimulation design maximizes infill production and avoids detrimental well-to-well communication, Eagle Ford Shale.