|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
A directional well can be divided into three main sections--the surface hole, overburden section, and reservoir penetration. Different factors are involved at each stage within the overall constraints of optimum reservoir penetration. Most directional wells are drilled from multiwell installations, platforms, or drillsites. Minimizing the cost or environmental footprint requires that wells be spaced as closely as possible. It has been found that spacing on the order of 2 m (6 ft) can be achieved.
ABSTRACT: A modern drilling testing facility equipped with a 375-ton, 1,500 HP drilling rig was built near Navasota in Grimes County, Texas. Starting 2014, more than 30 vertical/deviated/horizontal wellbores were successfully drilled and cemented back to shoe inside 20’’ and 13-3/8’’ casing after planned utilizations for testing were fulfilled for each individual wellbore. All the child welbores were drilled through one single parent wellbore. Non-reservoir shales and sands were penetrated in all drilled wellbores. Drilling and testing for vast amount of drilling automation, drilling optimization, rotary steerable systems, mud motor, MWD, reamer, agitator and other downhole drilling tools, surface rig-related tests and condition monitoring have been successfully conducted through these wellbores. For a new drilling field, it is imperative to build a geomechanical model to plan and execute safe and efficient drilling operations. Compensated neutron density log and sonic log were used to build the geomechanical model, together with offset and actual mud weights. Formation stress, rock strength, minimum mud weights and fracture gradients are modeled and calibrated using available drilling data such as leak off tests and lost return records. Future drilling and testing data can be used to continuously calibrate and finetune the geomechanical model. The modeling results can be used to quality control future deepened, deviated and horizontal well planning and borehole stability study.
One parent wellbore and 30+ child non-producing wellbores have been successfully drilled and cemented back to casing shoe in a modern drilling and testing facility during the past several years. The testing facility is located in Navasota in Grimes County, Texas and occupies 2000+ acres of lease. The testing facility is equipped with a modern Ideal Prime 1 drilling rig with the following technical specs .:
Abstract Characterizing vertical drainage in unconventional reservoirs developed using horizontal hydraulically-stimulated wells is a major challenge facing the E&P industry because there are few inexpensive, robust methods designed to measure vertical contributions. To overcome this challenge, ConocoPhillips has developed novel time-lapse geochemistry and production allocation techniques that utilize produced fluids (oil, gas, and water) to cost-effectively ascertain vertical drainage heights and provide information about vertical connectivity (or lack thereof) between stacked/staggered wells. In this paper, we present an overview of the geochemistry technique as well as geochemistry-based production allocation results in the Eagle Ford play. Over 3,000 time-lapse geochemistry samples have been collected over the last five years from over 150 Eagle Ford wells comprising more than 30 different pilot projects across ConocoPhillips more than 200,000-acre land position. The ‘fingerprints’ of the produced fluids have been quantitatively linked to specific stratigraphic layers using Eagle Ford core data. Key insights from this analysis are that vertical drainage is limited, varies across the acreage position, and is dynamic during production, usually shrinking with time. Results from time-lapse geochemistry have been integrated with multiple well pilot datasets (e.g., microseismic, soluble tracers, cores, image logs, pressure gauges in vertical and horizontal wells, and permanently-installed fiber optic cables) to optimize ConocoPhillips Eagle Ford development strategy. The outcome of these analyses has been the addition of approximately 1,200 drilling locations to the plan of development, which has significantly increased recoverable resources and asset value. Introduction Significant hydrocarbon resources are unlocked by horizontal drilling and hydraulic stimulation in low and ultra-low permeability (micro- and nano-darcy) reservoirs. Hydraulic fracturing creates a stimulated rock volume (SRV) around each producing lateral well from which hydrocarbons are accessed. The dimensions of the SRV are thought to be controlling factors in determining the optimal stacking and spacing of horizontal wells in a field development strategy.
McCaffrey, Mark A. (Weatherford Laboratories) | Al-Khamiss, Awatif (Kuwait Oil Company) | Jensen, Marc D. (ConocoPhillips Alaska) | Baskin, David K. (Weatherford Laboratories) | Laughrey, Christopher D. (Weatherford Laboratories) | Rodgers, Wade M. (Occidental Petroleum)
Abstract Using examples from the Permian Basin of Texas, the North Slope of Alaska, and the Bergan Field of Kuwait, this paper describes how oil geochemical fingerprinting can be applied to diagnose quickly and easily three production problems that may affect highly deviated wells. High-Resolution Gas Chromatography can be used to quantify ~1,000 different compounds in an oil, and the relative abundances of those compounds form a geochemical fingerprint. Geochemical differences between fluids in adjacent reservoirs can serve as natural tracers for fluid origin, allowing changes in production in highly deviated wells to be understood. Application 1: In wells that are fracture stimulated, oil fingerprinting can be used to assess whether induced fractures have propagated out of the target interval and into overlying or underlying formations. Oil fingerprinting can be used to quantify what percentage of the produced oil and gas is coming from each interval and how the effective stimulated rock volume changes through time. This concept is illustrated here with a Permian Basin example. Application 2: In wells with multiple laterals in the same well (such as those in certain North Slope, Alaska fields), sand can settle out of the production stream and form sand bridges that obstruct production from one or more of the laterals. In addition, sand co-produced with oil from shallower laterals can settle at the bottom of the vertical section during regular production and obstruct the entry to a deeper lateral. Geochemical fingerprinting can be used to determine quantitatively the contribution of each of several zones to a commingled oil stream. This technique allows the operator to identify sanded-out intervals for fill cleanout (FCO). Application 3: If two reservoirs are both oil bearing, but are of very different permeability, horizontal wells with an intended landing target in the tighter reservoir may be adversely affected if the well path contacts the more permeable reservoir. The Mauddud reservoir in Kuwait provides examples of this phenomenon. The Mauddud carbonate occurs between two massive clastic reservoirs, the Wara and the Burgan. Average Mauddud porosity is 18% with low permeability (1-10 mD), characteristics which make this reservoir a candidate for horizontal drilling. However, some lateral wells in this carbonate may encounter the adjacent, more permeable reservoirs over a short portion of the well path. In such cases, production from the adjacent reservoir may account for virtually all of the well's production, even though the well was intended to be completed solely in the tighter reservoir. Oil fingerprinting can be used to identify wells affected by this problem. A common theme unifies these three applications: Geochemical differences between in-situ fluids in adjacent reservoirs can serve as natural tracers for fluid movement. However, these techniques have been under-applied as tools for optimization of production from highly deviated wells. This paper illustrates the application of this technology to that well type in a variety of play types.
The Austin Chalk formation holds the potential for a resource development revival if the industry can look at it through "a fresh set of eyes," Tony Maranto, executive vice president and chief operating officer at EnerVest, told the SPE Gulf Coast Section's Business Development Study Group recently. Application of the latest technologies and development methods could "move the needle," he said, in a formation that has produced since the 1920s and has experienced more than one heyday--the last one in the 1990s as horizontal drilling was introduced. Maranto, a 35-year industry veteran, joined EnerVest in August 2016 after more than 20 years with EOG Resources. He stressed that he was giving his own views and not necessarily those of EnerVest, which is the largest producer in the Austin Chalk. "I'm not going to end this talk by telling what's going to happen in the Austin Chalk, but I will talk about what can happen," Maranto said.
Abstract The United States has had a significant oil and gas industry since Mr. Drake's oil well in Pennsylvania in 1859 attracted attention to the drilling of wells to produce oil. In the last decade, technology advances in both drilling and completion technology have had a significant impact on the ability to develop oil and gas reserves and have produced a new generation of wells for which extensive histories are not available at this time. A review of available historical data helps establish reasonable limits for decline trends of newer developments. In order to better place limits on terminal decline rates for unconventional plays, data are presented showing terminal decline rates for a selected vertical developments and for selected horizontal developments in the United States. The curves reviewed include 292 type wells in 54 different producing horizons in the United States. Some oil and gas developments have over 60 years of history and low decline rates. Others have high initial decline rates which do not flatten as expected for horizontal wells in low permeability reservoirs. The data for many of the developments also shows that decline trends beyond 10 to 20 years are frequently impacted by workovers and recompletions which have a significant impact on projected decline rates for a large number of long life wells. Where both vertical and horizontal wells have been developed in an unconventional play, vertical well decline rates are generally less than horizontal well decline rates. The data also shows that gas decline rates are generally less than oil decline rates. When considered as a group, there is a band of decline rates which establishes reasonable upper and lower limits for newer developments using horizontal drilling and newer completion technology.
The Wilcox formation in the Lower Tertiary is an interesting and challenging development. The industry is currently seeking ways to increase efficiencies, increase production, and optimize performance of this reservoir. This paper discusses the current status in generation V single-trip multizone completions as well as future prospects to predict industry options for the formation. This paper seeks to spur the industry into thinking about the future cost benefits and management of change necessary to design solutions for this unique development. Regarding Lower Tertiary wells, operators sometimes assume the wells are similar to the Wilcox formation in South Texas. However, studies indicate these wells should be treated like other Gulf of Mexico (GOM) wells, and they do require sand control. Is the industry willing to take these technical development risks? If unique solutions are proposed, what preparations are necessary, and how should planning proceed? There are unique solutions that operators can apply to the deepwater GOM as well as alternative solutions, processes, and procedures developed for land applications that can be adapted to the deepwater GOM. Land production has adopted the horizontal approach for efficiencies, but is this the correct approach for deep water? The multilateral approach is an interesting option that has been applied in other offshore environments, but is this a concept adaptable for the Lower Tertiary? How can monitoring and control be applied to these two concepts from land applications? How do operators take industry knowledge and apply it to the unique offshore environment of deepwater and subsea completions? The ultimate goal of this paper is to examine these questions and initiate the thought process of how the industry can optimize the returns from the Lower Tertiary by increasing production and recoverable reserves through technology and reservoir management.
Abstract Drilling time and cost were reduced in the Eagle Ford through the implementation of techniques and processes that resulted in 52% improvement in time and 45% reduction in cost. The shale revolution sparked an aggressive development campaign starting in 2010 in the Eagle Ford. Wells were drilled with a lack of appropriate knowledge of the area, without sufficient experience or proper equipment. Drilling costs were high but development was profitable due to the surge in oil prices. Drilling wells in the Eagle Ford is challenging because of the differences in lithology throughout the well, pore pressure profiles, high temperature, geosteering requirements, and casing design. These challenges had to be addressed in the design and execution of the wells. In addition, multiple trips due to downhole tool failures and low rate of penetration (ROP) contributed to high non-productive time (NPT) and associated costs. When Statoil took over the operatorship in the Eagle Ford an integrated approach to engineering and operations was key to optimize performance and bolster understanding of the area. Application of technology and standardization of operations resulted in continuous performance improvement. Detailed planning and execution, application of rotary steerable, implementation of an optimized casing design, contractor performance management, clear and open communication within the team, implementation of a performance incentive plan, and proper risk management all played a part in the overall drilling performance improvements. Over the past 2 1/2 years, more than 100 wells have been drilled in the Eagle Ford by Statoil. The techniques and procedures applied to optimize operations resulted in valuable lessons learned that can be applied to other development programs in the Eagle Ford and similar areas.
Abstract Faults and fractures are common features in many well-known reservoirs. In many of these reservoirs, horizontal wells are drilled to intersect a large number of fractures, particularly in low-matrix-permeability formations. In addition, the application of horizontal wells intersecting multiple hydraulic fractures has been widespread to allow shale gas and oil reservoirs, some of which are also naturally fractured, to produce economically. In this paper, we investigate the pressure transient behavior of horizontal wells in continuously and discretely naturally fractured reservoirs (NFR)s using semi-analytical boundary element solutions. These solutions have the advantages of the absence of grids and reduced dimensionality. Furthermore, they provide continuous rather than discrete solutions. The solutions are sufficiently general to be applied to many different well geometries and reservoir geological settings, where the spatial domain may include arbitrary fracture and/or fault distributions with different types of outer boundaries. A number of solutions have been published in the literature for horizontal wells in NFRs using the conventional dual-porosity models that are not applicable to many of these reservoirs. Most of these published solutions ignore the wellbore and the unfractured sections of the horizontal well. Therefore, they cannot capture the true early-time response, such as fracture radial flow. They may also yield incorrect damage skin values. Our solutions take these effects into account. Our solutions can also be applied to shale gas and oil reservoirs without shale-gas transport nonlinearities when the average reservoir pressure is above the desorption pressure. Our solutions for horizontal wells in fractured reservoirs can contain any spatial distribution of finite or infinite conductivity fractures with arbitrary length and orientation. The number and type of fractures (hydraulic or natural) intersecting the wellbore and with each other are not limited in both homogeneous and naturally fractured reservoirs. We present a number of examples to show different flow regimes that a horizontal well with multiple fractures exhibits, and to show that the conventional dual-porosity models simply do not work and can be deceptive. In our solutions, continuous and discrete conductive and nonconductive fractures are treated explicitly. The exact treatment of the uniform wellbore pressure condition, and the inclusion of the wellbore and the unfractured sections of the horizontal well have led to identification of new flow regimes that were not apparent from the existing solutions. Consequently, our solutions capture the true pressure transient behavior of the system, such as fracture radial flow. In this paper, a new classification of wellbore and fracture skin damage is given, and their effects on the pressure transient behavior are investigated. There are many factors that dominate the pressure transient behavior of horizontal wells intersected by multiple hydraulic fractures in naturally fractured reservoirs, such as fracture conductivities, lengths, and distributions, as well as whether or not fractures intersect the wellbore. Diagnostic derivatives plots are presented for a variety of horizontal wells with multiple fractures in homogenous and NFRs. It is shown that these reservoirs exhibit many different flow regimes. A multistage-fractured horizontal well in a very low-permeability shale reservoir example is also presented. Finally, we have presented two field buildup test examples from NFRs
Abstract The fishbones technology is a new well stimulation technique developed to increase well productivity index and improve reservoir connectivity to the well, being an alternative to hydraulic fracturing. This technique consists of creating several branches (holes) in the well using acid injection (dissolution and diversion). Those branches have small diameter and an average length of 40 feet. Main advantages of this technology over hydraulic fracturing are the competitive price and reduced operation time. In this paper we aim at modeling fishbones using the embedded discrete fracture model (EDFM), originally developed to model conductive faults and fractures. An EDFM preprocessing code was rewritten and extended to generate non-neighboring connections (NNC) between matrix, fractures and well connections; the NNCs were exported and used as input for a numerical simulator capable to handle NNCs. We modified the EDFM preprocessing code to adequately model fishbones. Each fishbone branch is treated as a fracture with dimensions equivalent to the branch dimensions (radius and length). The use of appropriate equations based on Peaceman's equation allows to model fishbones as equivalent fractures. Our new approach was used to perform sensitivity analysis (one at a time method) of the reservoir properties and the number of fishbones' branches for a case of primary oil production. A history match of the results of the first pilot using the fishbone technology was performed using an automated algorithm. Triple porosity cases were also evaluated and a good agreement between simulation and production data was obtained. A sensitivity analysis using design of experiments and the regression technique was used to compare the application of fishbones in different reservoirs (isotropic, anisotropic, and fractured) under primary oil production. The results of the simulations show that the fishbones is a promising stimulation technology that should be further evaluated.