Solvent huff 'n' puff (HnP) is becoming a common enhanced oil recovery (EOR) practice in unconventional tight and ultratight reservoirs. For an effective HnP operation, achieving miscibility is essential for promoting solvent transport into the reservoir matrix and subsequent oil production. This is typically achieved by either increasing the injection pressure or enriching the solvent. However, injection pressure is constrained by compressor capacity, formation fracture pressure, and lateral/vertical containment. In this study, we experimentally assess the feasibility of using natural gas liquid (NGL) for HnP in an ultratight Eagle Ford (EF) shale sample, providing insights into extreme solvent enrichment scenarios in an HnP process. We hypothesize that NGL extracts oil from an oil- saturated shale core through a counterdiffusion process, primarily governed by first- contact miscibility (FCM) between NGL and oil. In this study, we explore the impact of solvent injection on the phase envelope of both dead oil and live oil during the HnP process. We present a critical comparison between C1 HnP, representing the lower limit of solvent enrichment, and NGL HnP, representing the upper limit, focusing on their respective oil recovery mechanisms and in- situ solvent- oil interactions. Using a high- pressure and high- temperature (HPHT) visualization apparatus, we investigate the interactions between NGL and oil, as well as their compositional variations, under bulk- phase conditions and in the core during the HnP process. We propose an analytical theory for the transport of NGL and oil into and out of an ultratight porous medium, explaining the experimental oil recoveries observed from the shale core. NGL and oil transport is modeled under a diffusiondominated scenario, with FCM playing a crucial role in enhancing diffusion. Compositional analysis indicates that, contrary to C1, NGL extracts heavier oil components during the soaking stage. Core visualization demonstrates a gradual color change of NGL from clear to amber during soaking, indicating oil production via counterdiffusion. NGL expands the two- phase envelope of the dead oil, making it more volatile, while suppressing the phase envelope of the live oil. This potentially extends the duration of single- phase oil flow during the depletion stage in a live- oil system and enhances the oil production through diffusion. NGL achieves significantly lower FCM pressure (FCMP) with oil compared with C1, C1/C2 (70/30), C2, and separator gas, explaining its higher diffusion into the oil- saturated core. The analytical model demonstrates that NGL diffuses to the end of the core by the end of soaking. NGL recovers significantly more oil than C1 in the HnP process. Most of the oil is produced during soaking due to counterdiffusion, with solution- gas drive contributing additional recovery at later stages of depletion, though not as markedly as in C1 HnP.
Oil and gas field-produced water (PW) has emerged as a key source of lithium and rare earth elements (REEs). This study investigates the significant variance in lithium concentrations across different oilfields, with the Williston Basin in North Dakota having an average lithium content of 219.97 ppm. To be economically viable, lithium concentrations in produced water are required to exceed a minimum of 100 ppm. A novel approach integrating membrane filtration with economic feasibility analysis is proposed, offering a scalable solution for lithium recovery from highly saline PW. Experimental data obtained from Inductively Coupled Plasma-Optical Emission Spectroscopy (ICP-OES) demonstrates the effectiveness of this method, with recovery rates of up to 85
Abstract Although sucker rod connections are more understood now than they have been in the past, they are a surprisingly complex part of sucker rod operations, and we continue to learn about them. This study aims to further understand sucker rod connection make up variables, how those variables could affect operational reliability, and how to achieve optimal make up conditions. The variables considered were connections with and without pin lube, various coupling and rod grades, and sucker rod tong capabilities. This study was performed using connection make up and break out testing and secondarily rod tong diagnostics in the field. The connection make up and break out testing was performed using specialized sucker rod make up equipment that could measure make up and break out torque, as well as circumferential displacement. All the previous measurements were taken in varying connection conditions and combinations. This data was analyzed to understand how these conditions affect make up and back off torque. Concurrently with this testing, sucker rod tong diagnostic operations (torque/hydraulic pressure measurements) were being carried out in the field to understand the torque accuracy and capability of sucker rod tongs. The connection make up and break out testing revealed that connection make up without pin thread lubrication or with proper pin thread lubrication practices both yield acceptable back off torque values. Secondarily, the back off testing confirmed that there is considerable variation in torque necessary when varying rod grade, but not coupling grade. The sucker rod tong diagnostics revealed that many rod tongs do not reach manufacturer specifications for max torque and many also have considerable torque variation that could result in improper make up.
This paper recommends standardized names and equations for the two most common uses of Mechanical Specific Energy (MSE) concepts: "Total MSE" and "Downhole MSE". These names and their equations should be used uniformly in all applications, including electronic drilling recorder (EDR) pick lists, rig site surveillance, engineering surveillance, data analytics, research, and technical publications. Mechanical Specific Energy, used as a metric for drilling efficiency, is a mathematical calculation of the energy used per volume of rock drilled. The Downhole MSE equation calculates the efficiency of the bit alone, while the Total MSE equation includes both the bit and drill string. Those who use MSE in surveillance or analytics know the negative effects created by the lack of standardization over the years; it is certainly not a new problem. The lack of standardized nomenclature has resulted in the use of the same name for different equations, or different names are given two equations that are identical. This affects the ability of drill teams to engage vendors in redesign of performance limitations or to communicate new operational practices between teams or rigs. In addition, this standard corrects a mathematical error that is common in calculating the Total MSE. The concen with the inconsistencies has increased as MSE has become a key element in many automated optimization schemes. Inconsistencies or uncertainties in the basis of MSE values calculated in real time or shared in large data sets will affect the industry's ablity to develop useful analytics or to automate rig control platforms and data-driven decisions. This paper also includes a discussion of the MSE measurement errors and their effect on calculated values, which is of particular interest to controls engineers and those involved in data analytics. Examples are provided to illustrate how the two different MSE values are used in field operations. Also, a substantial reference list of current and potential future uses of MSE is included to encourage better MSE-based practices to potentially lead to the development of new uses in the future, including automation. This ad hoc MSE Standardization Committee is a volunteer group with representation from operators, rig contractors, service companies, and data acquisition vendors. The guidance given reflects there shared experienec in utilizing MSE in surveillance and analytics, and the recommended equations are technically correct.
This paper presents results from a collaborative industry study involving ten high-quality pad-scale datasets from the Delaware Basin, Midland Basin, Bakken, and Montney. The study had three primary goals: (a) compare/contrast observations between each dataset, (b) identify general strategies that can be used to mitigate parent/child impacts, and (c) provide concrete recommendations to optimize fracture design and well placement. For each dataset, an integrated hydraulic fracturing and reservoir simulation model was constructed and history matched to the observations. The models were calibrated to production data and pressure measurements, as well as to diagnostics such as: distributed acoustic sensing (DAS), microseismic, downhole imaging, chemical tracers, geochemical production allocations, and pressure observations from offset wells. History matching was performed by varying formation properties and model inputs to ensure consistency with the observations. Once the models were calibrated, the same set of approximately 120 sensitivity analysis simulations was performed on each model. Finally, an automated algorithm was used to quantitatively optimize fracture design and well placement to maximize economic performance. At each step in the process, the results were analyzed to identify the similarities and differences between the datasets and to explain why. The results show how differences in stratigraphy, well configuration, fracture design, and formation properties drive differences in parent/child phenomena. Optimal strategies to mitigate challenges depend on these site-specific conditions. Negative impacts from parent/child interactions cannot be entirely avoided. There is no strategy that can prevent the most important cause of child well underperformance – that wells are attempting to produce hydrocarbons from rock that has already been significantly depleted by parent well production. However, strategic design choices and quantitative economic optimization can significantly improve net present value and return on investment.
