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Although clustered perforations have become a primary choice of completion for horizontal wells in the development of low-permeability reservoirs, downhole measurements and production logging often indicate nonuniform production from the perforation clusters, with some of them not stimulated or not contributing to the production. One of the mechanisms contributing to this is nonuniform/inefficient breakdown of the perforations. However, being able to assess the effectiveness of perforation breakdown because of lateral variation of the formation properties and stresses is challenging, not only because of the lack of the data, but also because of the lack of a practical engineering model to predict the fracture initiation and breakdown pressures for cased and perforated completions due to the complexity of well configuration and perforation geometry. In this paper, an analytical fracture initiation model is presented along with the comparison against 3D numerical simulations and published experimental data. The breakdown pressure data from a Marcellus shale horizontal test well in the US Department of Energy (DOE)-sponsored Marcellus Shale Energy and Environmental Laboratory consortium are analyzed and compared to the model prediction using the highresolution 1D mechanical earth model derived from high-tier logs.
This paper revisits advancements in drilling high-temperature and high-pressure wells during the period 1950-1980. It was during this period that many of the planning and drilling techniques in use today were first identified, and in many cases, resolved on the drilling rig. The paper is drawn from personal recollections and published material, with particular emphasis on contributions from operator and service-company personnel at the rig site in the Gulf of Mexico and Gulf Coast basin. 1950 was a time when well kicks were "controlled?? on a local basis with whatever seemed to work, generally the constant annulus pressure or constant pit volume methods. Many of the well flows, fortunately, were saturated salt water and less hazardous than gas. Fracture gradient was an unknown value and stuck pipe and lost circulation seemingly occurred by happenstance. Mud solidification was similarly dealt with on a local basis with dilution of incorporated native solids and/or the addition of more dispersant in water-based muds. This also reinforced the importance of the high lime mud's ability to tolerate contamination.
The paper serves to highlight how resourceful field personnel working in concert with innovative staff engineers can achieve extraordinary success. This was and is especially critical in an industry fraught with uncertainty.
In 1950, the drilling industry had little idea of how to predict geopressures, a term coined by Charles Stuart,48, and even less of an idea of how to deal with High-Temperature, High-Pressure (HTHP) wells. The initial development of technology adequate to economically drill HTHP wells was piecemeal and by trial and error. Theory often followed practice. During the period 1950-1980, while there were some very notable exceptions, more typical deep well temperatures started to approach 300 °F and pressures approached 15,000 psi.
Geological papers published from the 1920's to the 1960's discussed earth temperatures and pressures from an academic viewpoint, 1,10,32,47,48,49 , but their value was not fully recognized until they were compiled with developing drilling technology in the late 1970's.
Higher temperatures and higher pressures required better drilling fluids leading to a progression from phosphate muds to high-lime, low-lime, gypsum, and lignosulfonate drilling fluids with 10% diesel oil that were more resistant to the conditions in the HTHP wells. At the same time, "true?? oil-based drilling fluids gave way to invert emulsions that ultimately resolved many of the problems with wellbore stability.
A landmark paper on well control methods by Obrien and Goins 38 opened the door to more discussion about predicting wellbore pressures instead of just reacting to them. The key thoughts about pressure caps and transition zones led to major breakthroughs in pressure prediction.
Mobile computing devices did not exist then, but special slide rules and nomographs were developed by different service companies to allow application of some of these techniques at the wellsite. By 1980, most of the new geopressured operating techniques were accepted as basic standards for HTHP drilling, and industry was starting incorporate predictive and operating procedures into computers that were becoming commonplace and readily available.
One of the major challenges of drilling and completion of oil and gas wells is the uncertainty in the formation fracture gradient and the fracture pressure. It is not uncommon that many drilling companies have spent money, resources and time in drilling and completing wells that should have been simply and optimally done. Fracture gradient evaluation constitutes one of the essential parameters in the pre-design stage of drilling operations, reservoir exploitations and stimulations. Several calculation methods and computer models have been presented in the literature for different regions of the world. Most of these techniques were based on either parametric or empirical correlations, which required a prior knowledge of the functional forms or the use of empirical charts which were not very accurate.
This paper presents an innovative method of predicting formation fracture gradient for Gulf of Guinea region. A combination of "Mathew and Kelly?? correlation, "Hubbert and Willis?? correlation and Ben Eaton mathematical models were used in developing the simplified technique based on field data from the Gulf of Guinea. The model compared favorably with the existing fracture gradient results in the Gulf of Guinea with less than 1 % deviation from other correlations thereby saving the rigors and time in using tables, charts and other long techniques. Although the method was developed specifically for the Gulf of Guinea, it should be reliable for other similar areas provided that the variables reflect the conditions in the specific area being considered.
Fracturing has become a viable and important option for completing horizontal wells. There are many fracturing processes and methods to consider for placement fractures. Optimization of the completion process including the number and size of fractures is still a challenge.
Although fundamentally similar to fracturing vertical wells, horizontal well fracturing has unique aspects that require special attention to ensure successful treatment. Differences exist between horizontal and vertical wells in the areas of rock mechanics, reservoir engineering, and operations. These aspects affect the optimization process for successful placement of treatments and optimum asset performance.
In this paper we discuss the various factors crucial to successful completion of a fractured horizontal well. We discuss these factors in relation to both longitudinal and transverse fracture applications. Success factors include the optimum perforation process, overcoming fluid flow convergence towards the wellbore in case of a transverse fracture, and the fluid flow and stress interference between multiple fractures.
The paper presents a field case and laboratory and numerical experimentations illustrating the impact of the various factors on the completion of the horizontal wells and the optimization of the fracturing process.