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Abstract In previous frac designs, proppant tracer logs revealed poor proppant distribution between clusters. In this study, various technologies were utilized to improve cluster efficiency, primarily focusing on selecting perforations in like-rock, adjusting perforation designs and the use of diverters. Effectiveness of the changes were analyzed using proppant tracer. This study consisted of a group of four wells completed sequentially. Sections of each well were divided into completion design groups characterized by different perforating methodologies. Perforation placement was primarily driven by RockMSE (Mechanical Specific Energy), a calculation derived from drilling data that relates to a rock's compressive strength. Additionally, the RockMSE values were compared alongside three different datasets: gamma ray collected while drilling, a calculation of stresses from accelerometer data placed at the bit, and Pulsed Neutron Cross Dipole Sonic log data. The results of this study showed strong indications that fluid flow is greatly affected by rock strength as mapped with the RockMSE, with fluid preferentially entering areas with low RockMSE. It was found that placing clusters in similar rock types yielded an improved fluid distribution. Additional improved fluid distribution was observed by adjusting hole diameter, number of perforations and pump rate.
This paper describes a novel process that uses standard drilling data obtained during the drilling of an infill well to identify induced hydraulic fractures that were created during the stimulation of a legacy well. Five case studies are presented to illustrate some insights gained through the application of this process.
This method of detecting fractures involves analyzing the amount of energy expended during the drilling of an infill well. Localized depletion around induced fractures created during stimulation of a legacy well and subsequent production can result in an increased differential pressure between the wellbore and the formation while drilling. This increased differential results in more energy being required to drill through the localized depletion caused by the fracture, allowing these fractures to be precisely located. Mapping these fractures allows operators to gain significant insight in to fracture growth and depletion patterns. In addition, by avoiding these areas of localized depletion during completion, negative fracture interactions can potentially be significantly mitigated or even avoided.
The 5 case studies presented show how this technique has been utilized to understand drainage patterns in stacked plays and how it can be used to understand the extent of dominant fractures being created as well as the horizontal stress orientation as indicated by the fracture direction. The method being deployed in this paper was developed, in February of 2019. This paper is the first to describe how this technique has been used in multiple applications, across multiple basins and reservoirs, to gain insight in to fracture growth and reservoir development as well as to mitigate fracture interactions which have been plaguing the industry.
As more unconventional resource development programs move to an infill drilling phase, understanding the interactions between primary/legacy (parent) and infill (child) wells is becoming more and more important. In some cases, these interactions are positive with no long-term damage to the parent well and can sometimes even increase the production. In many cases though, these "frac-hits" can be quite damaging to the parent wells with loss of production, increased water cut, sand fill, casing collapse or loss of the parent well. Loss of treatment fluid and proppant to the parent well can also mean that the child well is less effectively stimulated resulting in a reduction of potential production from the child well and lower ROI on the infill drilling program. It is because of these risks that many operators seek to minimize primary & infill well interactions.
Abstract The learning curve has evolved in the last few years for operators in shale plays. Early wells started with relatively large cluster spacing and small proppant volumes resulting in suboptimal initial completions. Over the years, perforation cluster spacing has declined. Consequently, the number of hydraulic fracturing stages has increased. The total proppant pumped per lateral foot has also increased. The majority of the existing wells were completed with geometrically spaced multiple perforation clusters per stage. Sometimes more than six clusters per stage have been employed. Studies have shown that one-third of these perforation clusters are not productive (Miller et al., 2011). Noncontributing perforation clusters could be due to not initiating hydraulic fractures, insufficient proppant placement, or loss of near-wellbore connection due to over-flushing or severe drawdown. Furthermore, during the development phase, the depletion from parent wells leads to asymmetric hydraulic fracture growth on closely spaced infill wells. Parent wells may also be negatively impacted due to hydraulic fracture interference from new completions. These factors have led to poor hydrocarbon recovery factors, sometimes less than 10% in horizontal shale wells. Recovery factors from existing wells can be improved through restimulation. Candidate selection is a key in achieving economically successful restimulation. Restimulation of appropriate horizontal shale wells resulted in significant production uplifts based on early field results. Designing a fit-for-purpose restimulation treatment is dependent on initial completion, offset well distance, infill plan, and, above all, economics. On top of the design aspect, operationally achieving effective restimulation on long horizontal wells with tens of perforation clusters is a challenging task. Thus real-time monitoring and control is a key for field execution. This work uses an integrated petrophysical, geomechanical, hydraulic fracture, and reservoir modeling workflow and field observations to develop restimulation strategies for improving hydrocarbon recovery. This integrated workflow includes a multistep calibration process to reduce uncertainty. One of the key calibration steps is to model hydraulic fracture growth accounting for local geological heterogeneity and match with observed treatment parameters and microseismic interpretations. Another critical calibration step includes automatic gridding of hydraulic fracture geometry to run numerical reservoir simulation to match realized production results. Reservoir pressure distribution at the end of the production history is used to recalculate stresses for modeling the refracturing scenarios. Multiple practical refracturing scenarios were constructed for addressing near-wellbore connectivity issues and ineffective drainage along the lateral. Creating new surface area in undrained rock and restoring productivity of existing hydraulic fractures resulted in higher recovery. Higher proppant amounts in undrained rock on one well pad or laterals with wider well spacing improved recovery. However, larger jobs can lead to significant interference for closely spaced wells. In conclusion, this paper demonstrates that properly designed restimulation treatments lead to improved recovery.
Abstract With the boom of the oil and gas activities in south Texas, our understanding of completions and completion optimization of multistage horizontal wells has been greatly enhanced. Various multiple-stage isolation techniques are currently being utilized. The success of any horizontal shale well depends on contacting maximum reservoir rock, causing operators to reduce interval length which, in turn, increases drilling and completions cost. To enable extending the interval length and increasing effectively stimulated rock volume, a new sequenced fracturing technique was developed and successfully tested. The technique relies on a novel fracturing fluid diversion blend delivered downhole at high concentration levels, which are achieved by using degradable fibers to stabilize fluid fronts and prevent slug dispersion when displaced. Thus, only a minor amount of material is used, and the pill is seamlessly integrated into a fracturing design and execution to divert stimulation fluids to under-stimulated regions of the wellbore. The material degrades completely after the fracturing treatment has been completed, leaving no residual formation or fracture conductivity damage. The technique was first applied on several wells without extending stage spacing. The consistent results and diversion performance led to introducing the technique to wells with increased stage spacing, with the objective of achieving higher productivity and higher operations efficiency. The early diagnostic data from wells completed with this technology demonstrate that diversion was achieved and reservoir contact improved. On wells with restricted internal diameter and long stage spacing, this technique was the only viable option to complete a section of the wellbore. Surveillance measurements indicate that the fracture treatment covered the interval as planned.
Jauregui, Jairo Leal (Saudi Aramco) | Malik, Ataur R. (Saudi Aramco) | Solares, J. Ricardo (Saudi Aramco) | Garcia, Walter Nunez (Saudi Aramco) | Bukovac, Tomislav (Schlumberger) | Sinosic, Brian (Schlumberger) | Gürmen, M. Nihat (Schlumberger)
Abstract Acid fracturing treatment performance is largely determined by the achieved effective etched fracture length. Evolution of fracture length during such treatments leads to progressively increasing the acid leakoff rate up to a point when the fracture stops extending. Zonal coverage and fluid loss control in naturally fractured carbonate reservoirs with high permeability contrast are the key challenges during acid fracture treatment. Nonreactive and reactive polymer based fracturing fluids and diverters were historically accepted as systems that could efficiently control fluid leakoff. The performance of such fluids relies on wall building fluid loss additives, such as polymers. Their deposition on the fracture face forms filter cake that decreases fluid leakoff into the formation. Filter cake on the etched fracture wall could cause skin. Nondegradable particulate fluid loss additives used in naturally fractured reservoirs can be a good leakoff control tool; however, particulates could permanently shut natural fractures off and obliterate their production contributions. Finding the right balance between induced fracture damage and conductivity is a challenge, and avoiding this damage by using nondamaging fluid with major fluid leakoff control properties is the logical problem solution. A novel fiber laden polymer-free self-diverting acid system was introduced in Saudi Aramco as an acid fracturing diverter to control fluid leakoff, and enhance the diversion process by combining the aspects of both particulate and viscosity based diversion techniques. The fluid system has a distinct advantage in that it does not contribute to formation damage because the viscoelastic surfactant will breakdown upon contact with hydrocarbons, and the fiber will degrade with time and temperature. More than 25 acid fracture treatments using the novel acid system have been successfully implemented in gas bearing carbonate reservoirs in Saudi Arabia. Unlike the approach used in acid fracture treatments using conventional fluid systems, the degree of diversion was dynamically adjusted to maintain the treating pressure above the fracturing pressure throughout the entire period in these treatments. The bottom-hole pressure (BHP) measurement confirmed superior fluid leakoff control leading to an outstanding diversion performance with excellent gas production increments. This paper provides details about treatment design, field implementation, and post-stimulation performance for two out of the more than 25 wells treated using this novel acid system.