The Cottage Grove formation is an active U.S. mid-continent play where cemented horizontal wells are traditionally stimulated by fracturing several perforation clusters simultaneously using limited entry "perf and plug" or other multi-stage completion solutions. Leaving sections of the lateral unstimulated when fracturing over a large interval can be even more severe in un-cemented completions, where the limited entry technique cannot be relied on to distribute the flow of stimulation fluids in the reservoir. Prior to the introduction of the sequenced fracturing technique, there was no solution to reliably stimulate a large un-cemented or openhole sections. This lead to potential losses of EUR in those wells where for some unplanned event, a section of the wellbore cannot be cemented or isolated with plugs. Recently, a well was drilled and unforeseen issues resulted in 3,300 feet of casing with a completely un-cemented annulus. A remedial cement job was not a feasible option and was quickly dismissed. It was decided to use a new sequenced fracturing technique to complete the stimulation without compromising EUR. This technique uses degradable fibers and multi-sized particles as a composite pill to temporarily plug the fractures and divert stimulation slurry to other regions along the wellbore. In this instance, 20 fracturing stages separated by 12 composite pills and 9 bridge plugs were pumped in sequence to optimize the number of fractures along the wellbore and maximize production.A production and radioactive tracer log run after the operation revealed that the composite pill successfully diverted the treatment fluids from areas previously fractured to previously unstimulated portions of the lateral. As a result, the entire lateral which had been left without cement was ultimately evenly stimulated. This was confirmed by a production log which showed a constant increase in oil and gas production compared to reference wells. Two hundred and six days after the well has been put on production, the well productivity has been more than 30% higher than any offset well.The design, execution and job evaluation of the treatments are detailed in this paper, and highlight the keys to the successful treatment which turned a well initially thought to be a failure into a technical and economic success.

Traditionally, surface pressure is the primary tool for onsite decision making during well stimulation treatments. In multi-stage wells with multiple injection points (perforation clusters) there are several available methods for diversion efficiency evaluation: differences in pumping pressure caused by pill pumping (also referred to as diversion pressure), instantaneous shut-in pressures (ISIPs) difference, and friction pressure difference. However, these techniques rely on interpretation of friction pressure or net pressure with uncertainties related to indirect measurements of the respective parameters. A high-frequency pressure monitoring (HFPM) service uses specially designed hardware and proprietary signal processing algorithms to determine the true location of downhole events. Bayesian algorithms are used to calculate probabilities of the interval’s stimulation. Effectiveness and applicability of the method were tested on several wells across major US shale plays. It was demonstrated that the industry standard surface pressure techniques are not always the best approach for the on-site decision making. Even when diversion is not clearly visible, it still may occur downhole. Conversely, a significant diversion pressure response does not necessarily mean adequate diversion. The effective application of the HFPM technique makes engineered decisions more confident during stimulation and diversion operations.

It is well accepted by the Oil and Gas industry that approximately 30%-40% of perforations or perforation clusters do not contribute to the production of a multi-stage fracturing stimulated well. Diversion is a common method to maximize the wellbore coverage. The objective of this study is to evaluate and maximize the effect of diversion in multi-cluster horizontal well hydraulic fracturing applications using water hammer profile analysis, step down test and microseismic monitoring. In this study, the authors demonstrated integrated approach for the well stimulation efficiency evaluation. A number of methods have been used for analysis: First, step-down tests after each stage have been used to estimate perforations accepting fluid. Second, innovative method of the high frequency surface pressure record analysis was used to detect diversion. Additionally, microseismic monitoring was used as an independent measurement that allows to validate the results. Eight wells were hydraulically fractured with multiple clusters per stage. Each stage is separated either by frac baffles or plugs. Diverter was pumped to promote more uniform wellbore stimulation. Shut- in procedure was implemented after each diverter step. Signatures of water hammer during shut-in are recorded by high frequency pressure gauge and analyzed in real-time using advanced algorithm from speech processing domain. Locations of clusters receiving fluid were calculated and diversion results are qualified. Microseismic measurements in some of the evaluated wells and step down tests are also performed to qualify the diversion process. All of these measurements were done in real-time and utilized to maximize the number of frac propagations, which will have a positive impact on production. This engineering technique allows the operator to make informed real-time decision based on the effectiveness of inter-stage isolation and diversion. Small footprint high frequency pressure monitoring (HFPM) allows the optimization of cost/BOE ratio.

More than 60% of US land wells drilled in 2017 are infill wells. Fracturing in such wells is likely to cause fracture hits on adjacent wells, which may have a negative impact on the infill and nearby existing well production. A new technology has been developed to control the geometry of the fracture, which reduces significantly the fracture hit rate and increases production in the child (infill) and parent wells. Traditional methods for controlling the geometry of hydraulic fractures include adjusting pad and proppant volumes and fluid viscosity. The proposed technology uses an alternative approach, delivering a multimodal particulate diversion mix with the proppant. The job is designed so that the diversion mix bridges and accumulates at the fracture tip, thus confining the fracture perimeter and controlling fracture length growth. The proposed technology has been field tested in 11 wells (219 stages) in the Eagle Ford shale. The results showed high efficiency of fracture hit prevention (84% of stages free of fracture hits) and increased production in the child and parent wells. The technology showed high operational reliability, (no premature screenouts) and was proven to be cost effective and robust. Laboratory experiments were conducted to tailor the permeability of the diversion blend. Because the diversion blend contains very small particulates, a wellsite delivery method was developed to prepare the blend and deliver it safely. Guidelines for the diverting pill pumping schedule were developed to optimize fracture hit prevention. The developed technology demonstrates that the complicated process of fracture growth geometry correction can be performed with intelligent engineering design including a far-field diversion pill.

Treating deep hot carbonate reservoirs, such as those found in the Arabian Gulf, presents a series of complex and related challenges to achieve effective and uniform stimulation. Due to the elevated temperature and heterogeneous formation, achieving good reservoir contact with an acid system along the entire interval of interest requires robust treatment fluids that can withstand the harsh environment. Recently, a novel single-phase retarded acid (SPRA) system and an engineered degradable large-sized particulate and fiber-laden diverter (LPFD) were introduced in a well in the Arabian Gulf, yielding strong results for the stimulation treatment. The SPRA, a 15% HCl-based acid system, showed excellent performance in a high-temperature environment (320°F). The fluid delivered similar friction pressures to unmodified 15% HCl, wormholing performance equivalent to emulsified acid without encountering the issues of fluid quality with respect to emulsion stability, and much higher dissolution power than organic acids and chelating agents. The pressure drop after the first acid stage was over 1,000 psi in about 60 min. After the second stage of acid, the pressure drop was close to 1,000 psi in about 30 min. Previous stimulation jobs in the region indicated a need for a significant amount of traditional diversion materials to achieve an effective plugging of the leakoff zones. A novel degradable LPFD system was introduced, achieving a significant increase of injection pressure (~1,000 psi) across the perforations. In addition to the effect on the diversion pressure, the implementation of the LPFD system has helped to reduce the footprint in offshore operations, has simplified materials handling, and has delivered the most efficient diversion performance in bullhead operations compared to other diverters. This article presents a novel method of stimulating deep hot offshore wells by combining an efficient SPRA and a unique degradable LPFD. These methods represent a step change to current practices and can be considered for effective stimulation in challenging carbonate formations.