Introduction The three primary functions of a drilling fluid--the transport of cuttings out of the wellbore, prevention of fluid influx, and the maintenance of wellbore stability--depend on the flow of drilling fluids and the pressures associated with that flow. For example, if the wellbore pressure exceeds the fracture pressure, fluids will be lost to the formation. If the wellbore pressure falls below the pore pressure, fluids will flow into the wellbore, perhaps causing a blowout. It is clear that accurate wellbore pressure prediction is necessary. To properly engineer a drilling fluid system, it is necessary to be able to predict pressures and flows of fluids in the wellbore. The purpose of this chapter is to describe in detail the calculations necessary to predict the flow performance of various drilling fluids for the variety of operations used in drilling and completing a well. Overview Drilling fluids range from relatively incompressible fluids, such as water and brines, to ...
Introduction The first hydraulic fracturing treatment was pumped in 1947 on a gas well operated by Pan American Petroleum Corp. in the Hugoton field. Kelpper Well No. 1, located in Grant County, Kansas, was a low-productivity well, even though it had been acidized. The well was chosen for the first hydraulic fracture stimulation treatment so that hydraulic fracturing could be compared directly with acidizing. Since that first treatment in 1947, hydraulic fracturing has become a common treatment for stimulating the productivity of oil and gas wells. Hydraulic fracturing is the process of pumping a fluid into a wellbore at an injection rate that is too great for the formation to accept in a radial flow pattern. As the resistance to flow in the formation increases, the pressure in the wellbore increases to a value that exceeds the breakdown pressure of the formation open to the wellbore. Once the formation "breaks down," a fracture is formed, and the injected fluid begins moving down the fracture. In most formations, a single, vertical fracture is created that propagates in two directions from the wellbore. These fracture "wings" are 180 apart and normally are assumed to be identical in shape and size at any point in time; however, in actual cases, the fracture wing dimensions may not be identical. In naturally fractured or cleated formations, it is possible that multiple fractures can be created and propagated during a hydraulic fracture treatment. Fluid that does not contain any propping agent (called the "pad") is injected to create a fracture that grows up, out, and down, and creates a fracture that is wide enough to accept a propping agent.
A variety of gases can and have been used for immiscible gas displacement, with lean hydrocarbon gas used for most applications to date. Historically, immiscible gas injection was first used for reservoir pressure maintenance. The first such projects were initiated in the 1930s and used lean hydrocarbon gas (e.g., Oklahoma City field and Cunningham pool in the US and Bahrain field in Bahrain). Over the decades, a considerable number of immiscible gas injection projects have been undertaken, some with excellent results and others with poor performance. This page discusses gas injection into oil reservoirs to increase oil recovery by immiscible displacement.
The first hydraulic fracturing treatment was pumped in 1947 on a gas well operated by Pan American Petroleum Corp. in the Hugoton field. Kelpper Well No. 1, located in Grant County, Kansas, was a low-productivity well, even though it had been acidized. The well was chosen for the first hydraulic fracture stimulation treatment so that hydraulic fracturing could be compared directly with acidizing. Since that first treatment in 1947, hydraulic fracturing has become a common treatment for stimulating the productivity of oil and gas wells. Hydraulic fracturing is the process of pumping fluid into a wellbore at an injection rate that is too high for the formation to accept without breaking.
A useful first step in the characterization of any new coal area is to compare its characteristics with those of successful CBM projects. Table 2 summarizes the characteristics of several successful projects in the US and includes parameters related to reservoir properties, gas production, gas resources, and economics. The table shows that successful projects have many similarities, including high permeabilities and high gas resource concentration; however, the table does not include aspects such as government incentives or high-value markets, which could elevate a marginal project to commercial status.
The process of drilling and completing coalbed methane (CBM) wells is similar to wells in conventional reservoirs. Coring, however, can pose special challenges. The first step in creating a drilling program for a CBM well involves gathering information about existing wells in a given area. After these data are gathered and analyzed, a preliminary drilling and completion prognosis can be drafted with the input of field operations personnel. An important aspect in drilling frontier or appraisal wells is to keep the drilling procedures relatively simple.
Haustveit, Kyle (Devon Energy) | Almasoodi, Mouin (Devon Energy) | Al-Tailji, Wadhah (CARBO Ceramics Inc.) | Mukherjee, Souvik (CARBO Ceramics Inc.) | Palisch, Terry (CARBO Ceramics Inc.) | Barber, Rusty (Formerly Devon Energy)
What is the number one problem with hydraulic fracturing and the frustrations that haunt every completions engineer? Our inability to see what is going on downhole during and after a hydraulic fracture stimulation job. This deficiency leads to numerous questions when attempting to optimize well performance and drainage, such as fracture extension, height growth, proppant/fluid volume usage, parent well depletion effects, cluster efficiency, etc. Over the years, several technologies have been used in an attempt to answer these questions including fiber optic, micro-seismic, chemical and proppant tracers, pressure matching and modeling. However, to date, none have been able to answer the most basic (and some would argue most important) question of all: where is the proppant located in the far-field?
A novel method that is gaining traction to answer this question is the use of electromagnetic (EM) technology to detect electrically conductive proppant. In this technology, a surface EM array is deployed and the EM field is measured both before and after the electrically-conductive proppant has been placed. Advanced modeling is then used to invert the before- and after-frac response to locate the proppant.
This paper will briefly review the technology as well as the motivation for deploying the process in one operator's STACK development. The paper will then thoroughly review a case history, where this EM proppant detection method was used in two offset infill wells in the STACK (Sooner Trend Anadarko Canadian and Kingfisher counties) play of Oklahoma. The two new wells were selected to be near the parent wellbore, where depletion effects were expected to impact both wells. The primary purpose of the project was to understand the impact the parent well had on an infill stimulation design.
Proppant maps will be presented which address the impact of the parent well depletion on the bi-wing fracture growth. Other complementary technologies will be presented including surface pressure monitoring of offset wells. This technology was also deployed previously in an area vertical science well and where applicable, these results will be included.
This paper will be useful for engineers, geoscientists and other technicians who wrestle with how to effective place their infill wells and design their fracture stimulations, with the goal of optimally depleting their acreage.
Jones, Drew (Deep Imaging) | Pieprzica, Chester (Apache Corporation) | Vasquez, Oscar (Deep Imaging) | Oberle, Justin (Deep Imaging) | Morton, Peter (Deep Imaging) | Trevino, Santiago (Deep Imaging) | Hickey, Mark (Deep Imaging)
We used a new, large-scale, surface-based, controlled-source electromagnetics (CSEM) approach to map the locations of frac fluid during flowback following a three-well hydraulic fracture stimulation in the Permian Basin. CSEM records and analyzes electric field signals induced in the electrically conductive frac fluids by a surface-based transmitter. For this study, we placed a grounded dipole transmitter directly above the central horizontal well of three parallel neighboring wells. The transmitted signal was a broadband pseudo-random binary sequence. To record the frac fluid response signal, we placed an array of 161 receivers on the surface covering the three horizontal wells. We recorded the induced, response signals of the flowback fluids in three-hour intervals (three on, three off) for 228 hours. The CSEM recording started eleven days after flowback began on the central well and four days after flowback began in the two outer wells. From this time-lapse recording we captured the spatial and temporal change in electrical conductivity within the fractured reservoir, allowing us to infer the location of flowback fluid and its movement. During the stimulations chemical tracers had been included in the frac fluid. Analysis of the tracers captured during flowback agreed well with the mapped fluid locations and movement found in the CSEM data.
Flowback monitoring and its interpretation offer another valuable tool for frac and reservoir engineers. This understanding is especially critical in developing and managing unconventional reservoirs. Here, the stimulation responses are not simple, more and more evidence show complex fracturing and complex fracture networks (e.g., Rassenfoss, 2018). Characterizing a fracture network or networks in shale (i.e., an unconventional reservoir) is a challenging task. It is complicated by multiphase and complex flow regimes, non-static permeability and porosity, natural fracture and flow systems, heterogeneities and complex stress, changing stress with production, liquid loading, and a host of operational concerns (Zolfaghari et al., 2016). In the past, to determine hydraulic fracture properties, operators used production data in a variety of models to manage wells and reservoirs. Garnering production data can take months or even years delaying, for example, upgrades to well and stimulation designs and designing infill drilling (Williams-Kovacs, Clarkson, & Zanganeh, 2015). In contrast, a flowback occurs during the transition between stimulation and bringing the well online. Understanding the flowback provides significant improvements in determining early production rates enabling estimates of the effective size of stimulations, distinguishing key reservoir properties, and predicting long-term production rates (Jacobs, 2016). In addition, there can be direct savings if, for example, flowback interpretation identifies an underproducing play in time to redirect funds into a more lucrative play before infill drilling (Williams-Kovacs et al., 2015).