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Summary In this paper, we provide some new insights into stick/slip vibration in drilling with polycrystalline diamond compact (PDC) bits. Fiftysix field runs under various drilling conditions were collected with the help of on-bit vibration sensors. Two types of stick/slip vibrations were identified: cutting-action-induced stick/slip and friction-induced stick/slip. Methods were developed to determine whether a stick/slip occurrence is induced by cutting action or by friction. Statistical analysis found that bit drilling efficiency (DE) is well correlated with the occurrence of cutting-action-induced bit stick/slip vibration. If a PDC bit is designed so that its DE is greater than a critical value, then the cutting-action-induced bit stick/slip vibration is not expected in drilling. Introduction Stick/slip vibration in drilling is one of the primary causes of cutter damage of PDC bits and early failures of downhole tools (Ledgerwood et al. 2013). Early efforts to address this issue were to measure downhole stick/slip by instrumenting vibration sensors near the PDC bits (Lamine et al. 1998) and near the roller cone bits (Chen et al. 2002). After the occurrence of stick/slip vibration in drilling is confirmed, efforts have been focused on understanding the root cause of stick/slip vibration of a PDC bit and the mitigation of stick/slip vibration during drilling. To better understand the root cause of stick/slip vibration of a PDC bit, three assumptions have been developed in the past three decades.
This paper discusses a new and general method of backup-cutter layout to extend bit life without sacrificing rate of penetration (ROP) and two field-case studies. This method includes the following aspects:
• Ensuring backup cutters do not cut or only partially cut when their primary cutters experience little-to-no wear and when the penetration per revolution of the bit does not exceed an expected value. This aspect is enabled by allowing backup cutters to have a minimal critical depth of cut that is greater than the depth of cut of the primary cutters.
• Ensuring that backup cutters act as active cutters when the primary cutters’ wear depth is equal to or greater than the underexposure of the backup cutters. This aspect is enabled by allowing each backup cutter to be rotationally behind its primary cutter by approximately 150° or greater. The underexposure of each backup cutter relative to its primary cutter is calculated carefully on the basis of the primary cutter’s wear and drilling conditions.
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.
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).
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.
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.
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 )
Results of Coreflood Test No. 2. Similar to coreflood test No. 1, the following test was initiated by flowing 5% NH 4 Cl in the Hassler sleeve, after which the primary HF acid formulation at a pH of 2 was injected at a constant rate of 1 mL/min for a total of 50 PVs. The primary HF acid formulation for this test comprised a combination of a proprietary α-HCA/HF acid (1% HF acid in 5% NH 4 Cl) and two surfactants. Subsequent to the injection of the primary HF acid formulation, 5% NH 4 Cl was flowed through the Hassler sleeve until a stable permeability was achieved. As can be observed in Figure 1, a permeability decrease (relative to brine) of 4% resulted from the injection of the primary HF acid formulation. Based on the results of the ICP-OES analyses displayed in Figure 1, the samples collected throughout the coreflood test revealed dissolution of formation minerals, such as silicon (as high as 2,075 ppm) and aluminum (as high as 685 ppm). Additionally, all effluents collected contained no observable precipitates, and all other ions were present in concentrations of less than 500 ppm. It is important to note that the pH of the spent HF acid formulation fluctuated from 2.27 to 2.57, as shown in Table 8.
Advanced Multi-Stage completion methods are game changers for oil and gas companies, turning previously uneconomic formations into attractive investments. The challenge in the Spearfish formation is generating and propagating the size of fracture required to maximize oil recovery, while avoiding penetration into an underlying water zone.
In the Spearfish formation the typical completion methods use pre-installed burst ports or pre-perforated zones, where each are isolated using a straddle system and then treated individually. These methods have shown to be especially effective; however, complications with burst ports not opening or not being properly located downhole have resulted in significant downtime and additional cost. Pre-perforated intervals have resulted in difficulty achieving breakdown and have also shown more communication issues to other zones. Additionally, these methods fix the depths at which treatments can be placed before the job begins, resulting in missed pay if unplanned events occur.
This paper introduces a new coil tubing deployed system which uses Hydrajet Assisted Fracturing (HJAF) technology to lower treatment pressures and optimize fracture extension in the zone of interest. This process offers a low-risk, operationally flexible, and efficient multi-stage stimulation method designed to reduce the time between stages and minimize the total fluid pumped into the reservoir. Also included is a detailed case history in the Spearfish that demonstrates how this process can maximize return on investment (ROI) for the operator.
Copyright 2013, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Unconventional Resources Conference-Canada held in Calgary, Alberta, Canada, 5-7 November 2013. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Economic success producing oil/gas from low-permeability shale often relies on preexisting 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).