As a result, the life of a PDC bit is limited. In other words, a PDC bit can drill only a certain distance or footage. To extend the life of a PDC bit, more diamond volumes or more PDC cutters are used. One method is to use backup cutters that form a second cutting layer in addition to a first cutting layer formed by primary cutters. Figure 1a shows that, in conventional designs, backup cutters were located rotationally behind their primary cutters on the same blades. Field observations confirm that backup cutters in conventional designs remove much less formation compared with their primary cutters but do wear at the same level as their primary cutters. Figure 1b depicts a typical case in which a backup cutter has similar wear as its primary cutter. The backup cutters might not be used properly in conventional designs. Although some successful runs have been reported (e.g., Gonzales et al. 2011; Teasdale et al. 2013; King et al. 2015; Abdullah et al. 2016), bit performance might be improved further if the angular locations and the underexposure of backup cutters are optimized.
Almost all previous cutter-force models assumed that cutting force was proportional to cutting area. Cutting-area-based single-cutter-force models were extensively used in polycrystalline-diamond-compact (PDC) -bit design optimization. This paper explains why cutting-area-based bit models failed to predict bit forces. A new cutter force model and a new bit model were developed and are discussed in the paper. In the new cutter force model, cutting force is a function of the shape of the cutting area. A common force model is developed for three types of cutting shapes. In the new bit model, 3D rock chips created in front of cutting face are modeled, meshed, and removed from the hole bottom by updating the hole bottom at each timestep. To validate the new model, four different PDC bits were designed, manufactured, and laboratory-tested under controlled conditions. Details from laboratory testing and field-test results are presented.
Various methods are used to overcome choking effects in propped fractures to enhance and maintain well productivity (particularly in low-permeability reservoirs). Choking effects can result from permeability damage caused by frac gel residue, proppant crushing from high closure stresses or use of low-quality frac sand, or embedment/intrusion of formation materials into the proppant pack. This paper describes development and field applications of a new well stimulation method for generating stable and highly conductive channels within a propped fracture to maximize transport capability of hydrocarbons from the formation reservoir to the wellbore.
Both extensive laboratory experiments and yard tests were performed to evaluate the formation and stability of proppant aggregates and proppant-free channels. Proppant-laden slurry (prepared by mixing frac sand coated with an agglomerating agent in a gel fluid) and crosslinkable proppant-free spacer fluid were pulsed intermittently to form proppant aggregate masses surrounded by proppant-free gel slugs. Highly conductive channels were formed surrounding the proppant aggregates after crosslinked gel slugs were broken and removed from the propped fracture, leaving behind proppant aggregate masses, supporting the closed fracture.
Field trial testing was performed in unconventional and conventional oil formations. Injecting pressures of proppant-laden slurry and proppant-free spacer using the pulsing approach were found to be significantly lower than those applied with conventional hydraulic fracturing treatments, indicating this new method helps alleviate the risks of screenout, as the proppant-free spacer sweeps and mitigates the proppant buildup in the near wellbore area. Field results showed production in wells treated with the pulsing method increased significantly compared to those of offset wells in which a conventional approach was taken. Additionally, 40% less total proppant was used when the pulsing method was applied.
Potential applications for this new stimulation method include the use of small-sized and low-quality sand. As long as the proppant aggregates remain stable, low-quality sands, such as desert or beach sand can be used. In addition, the operators now drill several horizontal wells from the same pad to target a shale play and perform multistage fracturing treatments in each well. The new method allows the operators to economically reduce the amount of proppant (and water) required as the number of fracturing treatments increases while, at the same time, minimizing the environmental footprint.
The rise in unconventional resource exploration relies on strategically placed sensors to record critical information during multiple forms of testing and reservoir enhancement techniques. The accurate data gained during the testing phases are what ultimately lead to the best flow regime design and successful optimization of the resources. New completion design or reservoir stimulation techniques are also effectively evaluated using data acquisition, aiding the development, refinement, and implementation of these techniques. However, suspension of the sensors in wellbores without decreasing flow can be challenging when introducing new techniques or modifications. Additionally, these flow-rate conditions can prevent the determination of production at the most economically advantageous time and rate.
This paper examines difficulties associated with acquiring data that can exist because of new completion designs or exploratory methods tested as a means to optimize a resource’s economic viability. Solutions offered by a new high-expansion hanger that can be used to meet these difficulties are also discussed. The tool has been proven to be a durable and flexible solution for an increasing array of completion and reservoir enhancement techniques for many styles and types of well testing under varying pressures and conditions. The tool is available in a wide range of pipe sizes and types, enabling positioning inside liner sizes of larger ID than that of the uphole completion tubing string within the wellbore. The high-expansion design also provides the assembly a generous bypass flow area, which helps increase the accuracy of the data received during flowing events.
Case histories are presented to illustrate the wide range of situations where the high-expansion hanger has been proven viable and a valuable solution for reservoir analysis and optimization.
Sopngwi, Jean-Jose S. (Marathon Oil ) | Gauthreaux, Alex (Marathon Oil ) | Kiburz, Daniel E. (Marathon Oil) | Sonnier, Baine (Halliburton) | Moghalu, David (Halliburton) | Smith, Steve K. (Halliburton )
Discovered in 1991 and located approximately 130 miles south of New Orleans, the Ewing Bank 873 (EW 873) field is an offshore mature field in the Gulf of Mexico that produces hydrocarbon from unconsolidated sandstone reservoirs of Middle-Upper Pliocene age. Most wells within the field were completed using cased-hole gravel packed completions, and field production began in 1994.
Throughout the production cycle of the EW 873 field, wells such as Well A-04 had experienced severe production impairment from near-wellbore (NWB) formation damage, as well as tubular buildups from barium sulfate (BaSO4) scale caused by incompatible mixing between formation water and biocide inhibited seawater that broke through from an offset injection well. While mechanical techniques such as coiled tubing-conveyed hydroblasting have been commonly used to remove BaSO4 tubular scale, the success of these techniques largely depends on the nature and magnitude of the BaSO4, as well as effective operational planning.
This paper presents the five-step engineered approach of the coiled tubing hydroblasting intervention that mechanically removed as much as 3,150 ft. measured depth (MD) of BaSO4 tubular scale from Well A-04. Additionally, the paper presents the tools that were utilized throughout the intervention and the laboratory and field methods that were applied to characterize the BaSO4. With NWB formation damage and production impairment already established to be a problem on Well A-04, the successful coiled tubing-conveyed hydroblasting intervention created an opportunity to effectively conduct a chelant-based hydrofluoric (HF) acid treatment that increased oil production by as much as 305% on the well (Sopngwi et al. 2014).
Sopngwi, Jean-Jose S. (Marathon Oil ) | Gauthreaux, Alex (Marathon Oil ) | Kiburz, Daniel E. (Marathon Oil ) | Kashib, Tarun (Marathon Oil) | Reyes, Enrique Antonio (Halliburton) | Beuterbaugh, Aaron (Halliburton) | Smith, Alyssa L. (Halliburton) | Smith, Steve K. (Halliburton )
The Ewing Bank 873 (EW 873) field is an offshore mature field in the Gulf of Mexico that produces hydrocarbon from Pliocene stacked turbidite sands. Wells on EW 873 have experienced production impairment from formation damage caused by aluminosilicates, fines, and scale including calcium carbonate (CaCO3) and barium sulfate (BaSO4).
This paper discusses the results of the successful application of a new chelant-based Hydrofluoric (HF) acid to remove formation damage and optimize production on EW 873. Additionally, the paper also presents the chemical analyses of acid flow backs, as well as the methods that were used to characterize the formation damage. More importantly, the paper also focuses on the multidisciplinary research efforts that led to the development and successful application of the new chelant-based HF acid.
Throughout the research, analytical experiments and corefloods were performed with three different HF acid formulations on cores that contained acid sensitive clays, CaCO3 and BaSO4. Two formulations contained hydroxypolycarboxylic acids such as citric acid, and the third formulation was based on the new chelant HF acid which contained an aminopolycarboxylic acid. The new chelant-based HF acid proved to be the most effective formulation as it achieved the highest permeability increase and dissolved ions while mitigating precipitation. Furthermore, compatibility and corrosion testing indicated that the new chelant-based HF acid was compatible with both the reservoir fluids and metallurgy of EW 873 wells.
The development of this novel chelant-based HF acid highlights the potential of performing successful acid treatments where heterogeneous mineralogy including CaCO3 and BaSO4 are present.
This work examines how the use of high salt content waters (i.e., produced and flowback water) in conjunction with a recently developed, virtually residue free (res-free) hydraulic fracturing fluid affects the cleanup properties of the system. The res-free fluid system is designed around a naturally low residue polymer that, upon breaking, causes significantly less damage to the formation and proppant pack compared with conventional, guar-based fracturing fluids.
Since its introduction, guar-based fluid technology has grown to dominate the hydraulic fracturing industry due to its reliability and cost-effectiveness. However, guar gum contains a significant amount of insoluble residue that is not removed during its processing. The residue can cause damage to both the proppant pack and the hydrocarbon-bearing formation when the broken fluid is flowed back following the fracturing treatment. This damage can impair hydrocarbon flow from the formation and through the propped fracture, resulting in lower production over time. The res-free fluid offers better cleanup upon breaking than guar-based fluids and therefore significantly higher proppant pack conductivity and formation permeability in laboratory testing.
The res-free polymer exhibits sensitivity to certain ions present in solution, both in terms of gel hydration and crosslinking behavior. Depending on the ions present in the water and their respective concentrations, manipulation of the chemical formulation of the crosslinked res-free fluid system can mitigate these effects and achieve a stable, highly viscous fluid suitable for hydraulic fracturing. This work investigates whether the necessary reformulations impact the regained permeability and conductivity of the fluid system. Rheological data demonstrating how the reformulated fluid compares to standard formulations is presented. Additionally, test results are presented highlighting the effects of the alternative water sources on the res-free fluid regained permeability and conductivity data.
The use of produced and flowback waters for fracturing operations can substantially reduce both the economic and environmental impact of fracturing operations. The combination of the res-free fluid’s ability to utilize these water sources and its excellent damage reducing properties provides a system with significant advantages over conventional technologies in many applications.
Economic success producing oil/gas from low-permeability shale often relies on pre-existing natural fractures (NFs) to be activated or connected by hydraulic fracturing (HF) stimulation. In practice, the reactivated natural fracture network is often identified using the microseismicity (MS) monitored during the stimulation. However, the fundamental mechanisms of MS generation and focal mechanisms inferred from geophysical analysis near hydraulic fractures are not currently well understood (e.g., it is not clear whether the MS observed in the field can be mainly attributed to local shear slip along natural fractures when leakoff occurs and/or induced by stress changes as a result of HF propagation or fluid leakoff). The exact slippage area and amount of slip displacement generating the microseimic event are not well understood either, thus requiring a "bridge?? between geomechanics and geophysics. To bridge this gap, a set of experiments will be performed in a geomechanics laboratory to observe whether, when, where, and how the acoustic emission (AE) events are generated under various scenarios. The experiments are designed under the guidance of fracture flow-discrete element method (DEM), coupling geomechanical simulations. In this paper, the reliability and accuracy of the fracture flow-DEM coupling approach is validated through solving a few fundamental problems and comparing the numerical simulation results with the corresponding analytical solutions. The coupling approach is then applied to simulate and optimize two fundamental laboratory experiments. The simulations indicate that, despite the difference in the magnitude, the local slip along natural fractures could be induced by both fluid leakoff and stress changes.
Long horizontal laterals with challenging well geometries and fracturing operations with 20-30 stages are commonplace in the US. Planning for successful completions operations that push the envelope of equipment and lateral reach is critical, and the ability to more accurately account for drag prior to running swell packers and frac sleeves downhole is needed to assist with the reliability of completions operations.
This paper will include an in depth look at the rig data, torque and drag models and the post job friction factors, which are an overall indication of the hole condition, for six wells. The post-job friction factors will be calibrated for drilling the final hole section and running the completions string, then analyzed to consider a link between the two operations. Production data will also be taken into account.
By creating a database of friction factors for completions operations that consider completion type, fluids used, use of centralizers, lithology and work string data, past experience has shown that even offset wells in the Bakken can have significantly varying amounts of drag. Analyzing the friction factors for drilling the final hole section will provide an opportunity to predict the level of drag prior to running the completions string.
This paper will provide the torque and drag analysis of both the drilling and completions operations for seven wells, along with a method to link the two operations. Conclusions will be drawn related to the variance between wells and the ability to predict the success of running completions strings to TD after gathering the hookload data and calibrating a post-job friction factor for the final drilled section of a well.
Although the results of the analysis will best apply to shale plays with similar geometries, the work method presented in the paper is applicable to any well construction scenario.
During the past several years, the oil and gas industry has increased the development of unconventional resource plays which are expected to hold the future for energy development in many parts of the world. In order to maximize these new reservoirs, horizontal wellbores are typically drilled, and multiple hydraulic fractures must be created to provide enough stimulated reservoir volume (SRV) to produce the wells economically. A traditional plug and perforate completion methodology has been employed to perform multi-stage fracture treatments, gain wellbore access, and isolate fracture stages. This process contains inefficiencies that can significantly impact economics. When the plug and perforate method is used prior to running perforating guns and a frac plug to depth, a flow path must be created at the toe of the wellbore. Typically, this is achieved by using tubing-conveyed perforating guns (TCP) deployed on coiled tubing (CT) or by a wireline tractor pulling perforating guns deployed on electric wireline (E-line). Although necessary, this process is one of the major plug and perforate inefficiencies noted in the above completion method. While it does allow casing pressure testing (either government-mandated or part of the operator's well construction "best practices??) prior to fracturing operations, it significantly impacts economics.
To address the inefficiencies, new technologies that seek to eliminate these problems, and thus, improve well economics are being developed. This paper explores an innovative pressure-actuated toe sleeve, which can eliminate running TCP on CT or perforating guns on E-line for initiating a flow path but still allows a casing pressure test to be run. Additionally, the pressure-actuated toe sleeve enables this casing test to be completed without having to exceed the casing test pressure to establish the flow path.
The design, testing, and use of the toe sleeve will be discussed in the paper.