_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 231225, “Modeling Parent/Child Effect in Vaca Muerta To Quantify the Impact of Infill Timing, Well Spacing, and Completion Design on Child Performance,” by Agustin Garbino, SPE, ResFrac, and Pavel Zuloaga and Gaston Mellado, Pluspetrol, et al. The paper has not been peer-reviewed. _ This work elaborates on recommended practices for calibrating a numerical model to a set of available infill-well field observations. The understanding of parent-/child-well effects plays a key role in defining the development strategy of shale plays. For this purpose, a commercial, fully coupled hydraulic fracturing, reservoir, and geomechanics simulator was used to model the area of interest. Results showed a strong dependence of child-well production losses on infill timing, well spacing, and completion design. Child-well estimated ultimate recovery (EUR) can range from 5 to 50% lower than parent wells within the ranges of well spacing, infill timing, and completion designs tested. Location and Field Diagnostics The area of study is La Calera, an unconventional gas condensate field with an area close to 230 km2. The studied site consists of a pad of three wells drilled and completed in 2020 next to another pad of three infill wells completed in 2022. All wells in each pad navigate different productive targets within the Vaca Muerta. A set of interwell-interference tests was conducted in these wells at different points in time, providing insights on the initial well communication and its development. The initial interference test was conducted in 2020 among the parent-pad wells during their initial flowback period, with Well P3 serving as the observation well with a downhole gauge installed. The test showed clear interference between P3 and its neighbors. Following approximately 2 years of production, the three parent wells were shut in. This shut-in period enabled a second interference test to be performed among the parent wells before childwell stimulation. Well P1 served as the monitoring well in this case, with a downhole gauge installed. The test showed no interference between the wells. Frac-hit events were recorded and quantified through wellhead-pressure measurements on the parent pad during the completion of the offset child wells. The results showed strong fracture-driven interactions (FDIs) between all the wells landed at the same bench, and interbench communication between Wells C2 and P1. After completion of the child-pad stimulation, a third interference test was performed among the parent wells to identify potential changes attributable to the stimulation in the child pad; however, the results of the pressure signature were inconclusive. Lastly, upon initial production startup of the child wells, a fourth interference test was conducted between the parent and child wells. Again, the pressure response in monitoring Well P1 is not overly clear, but a clear response is noted when Well C2 is opened, indicating some level of communication.
_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 36051, “Enriching Productivity by Using Organophilic Clay-Free Reservoir Drilling-Fluid Technology on Tight Reservoirs,” by Mohamed H. Madad, Ahmed A. Abulnasr, and Mohamed Elmashad, Halliburton. The paper has not been peer-reviewed. _ This paper presents the methodology for developing drill-in organophilic clay-free invertemulsion- fluid technology that enhances well production through fundamental geological studies and fluid testing. Maximizing asset value is a major drilling challenge in supertight fields. This paper presents the methodology for developing drill-in organophilic clay-free (DIOCF) invert-emulsion-fluid (IEF) technology that enhances well production through fundamental geological studies and fluid testing. Using a customized DIOCF system resulted in successful drilling and completion of substantially tight-permeability reservoirs. Lithology The target reservoir is a significant Ordovician-age geological formation. It is characterized by tight sandstone formations primarily composed of mature quartz arenites with a high silica content. The reservoir consists predominantly of quartz arenites, indicating a mature sandstone with extensive quartz overgrowth. The presence of natural fractures, ranging from partially open to closed, has been observed, which can affect fluid flow and reservoir performance. These fracture systems often are oriented parallel to the regional tectonic stress field and are mineralized with quartz and minor calcite. Geomechanical modeling of the quartzite reservoir revealed that it is a mechanically competent formation. The formation’s high stiffness supports its ability to resist wellbore collapse; however, its natural fracture system renders it susceptible to severe mud losses if not effectively managed.
_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 227670, “Enhancing Drilling Efficiency: Real-Time Rheology and Density Profiling With RheoProfiler in Saudi Arabia’s Ghawar Gas Field,” by Arnott Dorantes, SPE, Raed Ghali, SPE, and Diana Torres, SPE, SLB, et al. The paper has not been peer-reviewed. _ This paper presents the large-scale deployment and operational integration of an advanced, automated rheometer in the Ghawar gas field, one of the world’s most prolific and technically complex hydrocarbon developments. As drilling operations evolve toward greater digitalization, the demand for real-time data, automation, and integrated workflows has increased significantly. This paper presents the large-scale deployment and operational integration of the RheoProfiler 200, an advanced, automated rheometer, in the Ghawar gas field, one of the world’s most prolific and technically complex hydrocarbon developments. The device, in combination with a drilling-fluids advisor and a mature real-time operations center (RTOC) framework, was implemented to overcome longstanding challenges in drilling-fluid monitoring, including delayed data, human error, limited data accessibility, and reactive decision-making. RheoProfiler The device is an advanced, fully automated rheometer specifically engineered for testing the density and rheological properties of drilling fluids, including water-based, oil-based, and synthetic mud systems. Weighing approximately 34 kg, the unit is designed for indoor operation and is ideally suited for installation in fluids-engineer cabins at the rig site. This device enables consistent and reliable mud testing while minimizing manual intervention. It performs key measurements including mud weight (density), plastic viscosity, yield point, and gel strengths (10-second and 10-minute) and transmits the results by wellsite information transfer standard markup language protocol to centralized data platforms. Although real-time data transmission is supported, results typically are reported with a short delay of a few minutes, depending on operational workflows.
_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 230625, “Simulation-Driven Optimization of Simultaneous Frac-Execution Strategies: Tradeoff Analysis of Two- and Three-Well Simul-Frac, Cost Models, Operational Efficiency, Flow Rates, and Stage Lengths,” by Brandon Eidson, SPE, PrePad, and Luisa Porras, SPE, and Mike Zimmerman, SPE, Birchcliff, et al. The paper has not been peer-reviewed. _ This paper focuses on a replicable, quantitative workflow using completions-process simulation software. Simultaneous fracturing (simul-frac) operations can offer efficiency gains by distributing total flow. The need to maintain a minimum rate per cluster or perforation friction often requires reducing clusters per stage, however, leading to more stages for the same lateral length. These factors introduce a complex set of tradeoffs between energy-efficiency gains and operational penalties. The complete paper introduces a replicable, quantitative workflow using completions-process simulation software. The process transforms a traditionally experience-heavy domain with low-fidelity models into a structured, data-rich decision space applicable across operators and basins. Analysis Approach The analyses performed relied heavily on commercially available simulation software specialized in simulating the horizontal well completions process. The software includes physics-based models capable of predicting pumping pressures and flow rates under most circumstances, including tracking minimum flow rate per cluster so that design requirements can be upheld while optimizing lateral designs. Furthermore, the software includes a discrete event, completions-process simulator with an optimal-fracture-order optimizer scalable to the diverse, complex combinations of designs, well counts, and simul-frac scenarios. Finally, detailed contractual inputs are included so that precise, accurate cost effects can be predicted. The first three scenarios the authors offer in the paper represent operations constrained on maximum fracture-spread flow rate (because of single-blender limitations) and maximum sand consumed per day (because of sand-delivery limitations). The later scenarios significantly lift these constraints.
Digital frameworks and autonomous operations are transforming the future of flow assurance. Recent developments in flow assurance feature three core trends: infrastructure optimization for decarbonization, autonomous well interventions, and hybrid modeling. The industry encounters persistent challenges regarding uncertainties in multiphase flow measurement, pipeline integrity for CO2 under transient conditions, and scale management in deepwater environments. Overcoming these limitations necessitates a transition from reactive empirical correlations to proactive digital frameworks and autonomous operations. Paper SPE 225871 details a real-time process twin for a large-scale network for carbon capture and storage. By forecasting critical thermodynamic parameters, continuous surveillance allows operators to optimize the transport of dense-phase CO2 and prevent accelerated corrosion during unplanned shutdowns. Paper OTC 36149 presents an autonomous methodology for the chemical treatment of inorganic scale in ultradeepwater carbonate reservoirs. Using existing completion rig infrastructure instead of conventional stimulation vessels reduces operational costs, logistical complexity, and the emission of carbon equivalents. Paper SPE 228033 introduces a neural network constrained by fundamental physical laws to solve Navier-Stokes equations for multiphase flow measurement. Embedding mass and momentum conservation directly into the training process improves prediction accuracy across varying flow regimes and minimizes reliance on empirical calibration.
