Understanding reservoir-rock characteristics and the forces that mobilize oil in unconventional reservoirs is critical in designing oil-recovery schemes. Thus, we conducted laboratory experiments for three preserved Middle Bakken cores using centrifuge and nuclearmagnetic-resonance (NMR) instruments to understand oil-recovery mechanisms in the Bakken. Specifically, we measured capillary pressure, pore-size distribution (PSD), and oil and brine saturations and distributions.
A series of oil/brine-replacement experiments (drainage and imbibition) were conducted for the preserved cores using a high-speed centrifuge. T2 time distribution and 1D saturation-profile measurements were obtained using a 2-MHz NMR instrument before and after centrifuge experiments. Moreover, PSD was determined from mercury-intrusion capillary pressure (MICP) and nitrogen-gas-adsorption experiments. We conducted scanning-electron-microscope (SEM) imaging on polished cubical cores to determine pore shapes and mineralogy of pore walls using a field-emission SEM (FE-SEM).
Our measurements show that these three preserved Middle Bakken cores show mixed-wet characteristics. Water resides in smaller pores and oil resides in larger pores in all experiments. Using a low-salinity synthetic brine of 50,000 ppm to surround Bakken cores of much-higher salinity, we produced up to 6.33% [of pore volume (PV)] oil from two higher-porosity (approximately 8%) cores, and 10.72% (of PV) oil from one lower-porosity (approximately 2%) core in a spontaneous-imbibition (SI) experiment. Up to 6.62% (of PV) oil from the two higher-porosity cores and 11.23% (of PV) oil from the lower-porosity core were produced in a forced-imbibition (FI) experiment as well. These experiments indicate that molecular diffusion/capillary osmosis overrides the wettability effects in low-permeability Middle Bakken cores. The new observations regarding molecular diffusion/capillary osmosis have altered our classical notion of capillary imbibition in low-permeability reservoirs.
After spending four years in a close partnership, an independent E&P operator and a services company collaborated in rolling out a progressive well integrity management methodology across operations in West Africa, North Sea, Gulf of Mexico and onshore USA (conventional and shale) has been delivered using a software framework.
This paper describes the process of how the software was configured and adapted to meet the demands of varied well operations and well production types, while also supporting an objective to deliver a standardized view of well integrity across the organization. The incorporation of consistent practices to support the operator's integrity program, including those laid out in ISO 16530-2[
Furthermore, this paper discusses the practical challenges of implementing a system of this type and the steps taken to ensure the system was incorporated into the operating plan across a diverse portfolio of well types and operating environments.
The implementation project and its results are described, exploring the key factors that contributed towards its success, including user case examples. The paper discusses future areas that may add further value to the safe operation, reliability and the integrity of the operator's assets.
The StressCage methodology of wellbore strengthening uses sized particles to bridge and seal induced fractures, increasing fracture resistance in permeable formations. The size distribution of the particles, or fracture prevention material (FPM), that are added to the mud is engineered to ensure correctly sized particles enter and bridge the induced fracture before it grows beyond its designed width and length. A minimum concentration of FPM is determined through a physics-based numerical calculation to derive a mud formulation based on the particle size distribution (PSD) and density of the selected mud additives. This minimum concentration and particle size distribution of FPM must be maintained at all times that the wellbore pressure exceeds the fracture gradient or previously generated fracture resistance of the formation in order to prevent the failure of the StressCage and the subsequent loss of wellbore integrity.
A number of methods have been used to monitor FPM concentration in the mud. Most methods sample the mud returning from the well before arriving at the mud shakers, pass the collected mud sample through stacked sieves, remove the liquid mud coating the particulates using either centrifuges or drying ovens, and weigh the resulting residue to determine the return concentration. These methods can be inadequate and difficult to implement due to the requirement of specialized equipment on the rig (ovens, laser PSD, centrifuges, etc.), the need for additional personnel to conduct the mud monitoring activities on the rig, and the significant delay in obtaining the results. The lag time for results in deepwater wells can be 5 to 10 hours, depending on the time required to circulate the mud up the well and dry the samples. This delay can prevent operators from detecting when FPM concentration decreases to below the minimum required for drilling depleted sands.
A simple and fast method has been developed that requires minimal special equipment. A reference sample is collected from a reserve mud pit carefully prepared with the target minimum FPM concentration. The mud is then run though a set of selected stacked sieves. The reference tare weights of the wet FPM collected in each sieve are used as a reference for monitoring the active system. The reference wet FPM weight is compared to mud samples collected from the suction pit of the active system as the well progresses. The difference in the weight observations is then used to determine appropriate additions to maintain or exceed the minimum requirements.
Saini, G. (The University of Texas at Austin) | Chan, H. (The University of Texas at Austin) | Ashok, P. (The University of Texas at Austin) | van Oort, E. (The University of Texas at Austin) | Isbell, M. R. (Hess Corporation)
Substantial volumes of data are collected during modern drilling operations. However, the business value of such data is limited unless it can be analyzed quickly to derive practical knowledge for application on subsequent wells. The sheer quantity and messiness of data can overwhelm oilfield personnel, making it difficult for them to extract value. An automated process is necessary to extract knowledge quickly and efficiently from large datasets. Our team identified a preliminary set of 12 questions with answers that provide immediate knowledge to help improve the drilling of subsequent wells. Each of these ten questions is best answered through a storyboarding process. The process involves the automatic creation of a series of one-page visuals with just the right amount of information on each page to validate the answers to the questions. Standardizing the structure of the data (well-site data, survey data, geology data, well plans, etc.) enables software to rapidly create these visuals and is an important step in the process.
This work describes how the storyboarding process was applied to a dataset of more than 100 gigabytes (GB) from 16 shale wells drilled in North America. Examples of questions that could be quickly answered using the process are: ‘What was the best drilled well on the pad?’ and ‘Did a particular bottom hole assembly (BHA) improve drilling in a particular section of the well?’ Scripts were written in Matlab and Python to automatically process the raw data and generate more than 20 different types of one-page visuals that are well suited to present the answers to such questions. The illustrated information includes insights into BHA performance, wellbore tortuosity and quality, vibrations, weight on bit transfer, and other drilling dynamics. Identifying the relevant KPIs to satisfactorily answer the questions and present exactly the right information from the vast amounts of data was a challenge. This paper documents and describes the concept of storyboarding that uses visuals to answer comprehensive questions. This concept is not yet widely applied in the drilling industry today, but is expected to be quickly adopted by stakeholders interested in drilling performance improvement and cost saving opportunities.
Early in 2017, initial discussions began to define an Automated Remote Drilling project that would use a centralized command center and specialized distributed software systems to automate the directional drilling decision-making workflow and the implementation of these decisions at the rigsite. The objective of this de-manning of directional resources at the rigsite was to enable the Operator's in-house directional supervisors to efficiently and safely control a larger number of rigs than was previously possible with legacy work practices and software.
In addition to the standard high-speed data links from office to rig, the project was based on an automated directional software guidance system configured to optimize directional motor slide drilling. This integrated directional navigation software suite also communicates directly with the top drive directional control system to ensure slide commands are implemented exactly as calculated. The software suite captures and assesses the effectiveness of slides automatically and uses sophisticated steering logic and steering targeting systems to support directional drilling best practices and geo-steering adjustments in the production zone.
The paper presents aggregated feedback from directional drillers on the automated systems' decisions and the results of following system directives in the low angle and nudge sections, in the curve, and in the lateral wellbore. Case studies are presented, along with summaries of the workflow changes implemented in town and at the rigsite. Several current lateral Bakken wells are presented as evidence of the effectiveness of the Automated Remote Drilling project approach and the benefits of this level of collaboration between a forward-looking Operator and drilling contractor.
The combination of the directional navigation software, the automated implementation, the geo-steering support, and a new Automation Assisted Workflow presents a new approach to an industry-wide challenge in the current market of how to do more with less without compromising efficiency, safety, or intervention capabilities.
Successful operation of an offshore field relies heavily on a surveillance program to monitor and describe the dynamic status of the wells. Conventionally, such programs consist of a series of shut-in and wrap-up procedures to collect essential buildup/drawdown pressures for inferring the near wellbore status, drainage volume, well productivity index (PI), etc.
Such surveillance programs are complex and expensive. They require long well shut-in periods, which may be infeasible both economically and operationally in certain scenarios. Although a long shut- in may be prohibitive, pressure buildup data from planned or unexpected short shut-ins are often available in offshore fields.
This paper presents an innovative methodology to infer the necessary information from short shut-in data. The main theoretical basis for the new method is the decomposition of the energy dissipation during the pseudosteady-state flow period. By decomposing the energy loss into time dependent and time invariant components, the dynamic status of the well(s) can be described using available Create the evolution of the well skin and well PIs Estimate the well's drainage volume Detect/confirm aquifer support Pinpoint the well workover/stimulation threshold and timing Assess the work quality of the workover/stimulation
Create the evolution of the well skin and well PIs
Estimate the well's drainage volume
Detect/confirm aquifer support
Pinpoint the well workover/stimulation threshold and timing
Assess the work quality of the workover/stimulation
This paper describes the theory and physics behind the methodology and demonstrates its application in an offshore field example.
This paper details the results from a comprehensive study to evaluate completion effectiveness and optimize field development in the Utica. Optimizing the number and location of perforation clusters, number of stages, and treatment size requires a clear understanding of how these parameters affect fracture geometry and well productivity. The goal of this work was to determine how the number of perforation clusters per stage and treatment size affect fracture geometry and well productivity, and to integrate these results into the overall field development optimization.
A comprehensive evaluation of plug and perf (PNP) and controlled entry point (CEP) completions and treatment size was performed using a five-well pad in the Utica (wet gas area). The evaluation included PNP completions with 3-4 perforation clusters and CEP completions with 1-2 perforation clusters. Treatment size was varied by a factor of two to evaluate the effect of fluid volume on fracture length. Microseismic data were gathered on 81 PNP stages and 95 CEP stages. The microseismic data were used to calibrate hydraulic fracture models. Fracture geometries for the five-well pad plus a direct offset well (a six well total of 250+ stages) were discretely gridded in a reservoir simulation model. The reservoir simulation model was calibrated by history matching 14+ months of production data. Proppant Tracer data and DFIT measurements from previous Utica work were used to support the hydraulic fracture modeling and reservoir simulations.
The microseismic data provided a clear understanding of the relationship between treatment size and fracture length for each completion scenario. The results indicate that fracture length may be dependent on completion type, with CEP completions showing less fracture length than PNP completions. Simple production comparisons and detailed reservoir simulation history matching showed that (1) well productivity is governed by the number of perforation clusters, with PNP wells outperforming CEP wells and (2) well-to-well communication is evident. This work did NOT identify any gross inefficiencies with PNP completions and suggests that CEP completions do NOT result in better productivity, at least in this Utica pad.
The calibrated models were used to optimize perf cluster spacing, treatment size, and well spacing for PNP completions. The optimization results are summarized in the paper, but the focus of the paper is the evaluation of PNP and CEP completions, characterization of hydraulic fracture length-volume relationships, and calibration of hydraulic fracture and reservoir simulation models.
A year ago, this feature noted the continued languishing of crude-oil prices and the low margins in tight and very tight reservoir asset developments and the resulting substantial reduction in new-well drilling and completion. Little has changed since then. In the meantime, technology advancements have enabled a greater number of hydraulic fractures in long horizontal completions in such reservoirs, for example, resulting in more-cost-effective completions and greater initial oil-production rates. But low primary oil recovery and steep initial-production-rate declines still present overriding limitations. These tight and very tight oil-bearing reservoirs are typically characterized by oil-recovery factors of approximately 10%. However, on a positive note, in addition to improvements in completion efficiencies, recent advancements also have been made in the understanding and application of enhanced-oil-recovery (EOR) methods in such reservoirs.
While enhancing oil production from multizone, hydraulically fractured completions in tight reservoirs is not straight forward, recent studies, including field trial programs, have shown that applications such as gas injection and waterflooding, including smart water injection, have the potential to create significant improvement in oil recovery.
The three papers featured this month are from Canada. All address the importance of wettability and wettability alteration in improving sweep efficiency and oil extraction by use of gas injection or water injection. Both laboratory studies and field application, in the case of waterflooding, are discussed. Each, with their unique perspectives and approaches, provides understanding of EOR fluids; formation interactions; and the benefits and present limitations of gas injection, conventional waterflooding, and smart water injection.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 185037 EOR in Tight Reservoirs—Technical and Economic Feasibility by K. Joslin, Computer Modelling Group, et al.
SPE 185680 Compositional-Simulation Evaluation of Miscible-Gas-Injection Performance in Tight Oil Formation by Ahmed Mansour, Texas Tech University, et al.
SPE 180284 The Use of Propellants To Stimulate and Enhance Productivity From Tight, Damaged, and Low-Quality Reservoirs by J. Gilliat, Baker Hughes, et al.