Fracturing Technology - Can We Finally Control Fracture Height?

For as long as we have been performing hydraulic fracturing, we have been trying to ensure that we stay out of undesirable horizons, potentially containing water and/or gas. The holy grail of hydraulic fracturing, an absolute control of created fracture height, has eluded the industry for more than 70 years. Of course, there have been many that have claimed solutions, but all the marketed approaches have at best merely created a delay to the inevitable growth and at worst been a snake-oil approach with little actual merit. Fundamentally, the applied techniques have attempted to delay or influence the underlying equations of net-pressure and stress variation; but having to ultimately honour them and by doing so then condemned themselves to limited success or outright failure. Fast forward to 2020, and a reassessment of the relative importance of height-growth constraint and what may have changed to help us achieve this. The development of unconventionals are focused on creating as much surface area as possible in micro/nano-Darcy environments, across almost any phase, but with typically poor line of sight to profit. However, the more valuable business of conventional oil and gas is working in thinner and thinner reservoirs with an often-deteriorating permeability, but with a significantly higher potential economic return. What unconventional has successfully delivered however, is a rapid deployment and acceleration in a range of completion technologies that were unavailable just a few years ago. We will demonstrate that these technologies potentially offer the capability of finally being able to control fracture height-growth. Consideration of a range of previously applied height-growth approaches will demonstrate how they attempted to fool or fudge height growth creation mechanisms. With this clarity, we can consider what advances in completion technology may offer in terms of delivering height growth control. We suggest that with the technology and approaches that are currently available today, that height-growth control is finally within reach. We will go on to describe a multi-well Pilot program, in deployment and execution in 2020/021 in Western Siberia; where billions of barrels remain to be recovered in thin oil-rim, low permeability sandstone reservoirs below gas or above water. A comprehensive assessment of the myriad of height-growth approaches that have been utilized over the last 70 years was performed, but in each case demonstrated the fallibility and limitations of each of these. However, rather than the interpretation that such control is not achievable, instead we will show a mathematically sound approach, along with field data and evidence that this is possible. The presentation will demonstrate that completion advances over the last 10 - 15 years make this approach a reality in the present day; and that broader field implementation is finally within reach.

No Need for Radio Active Tracer When Mother Nature Helps Detecting the Effective Hydraulic Fracture Height

The tight gas reservoirs of Haima Supergroup provide the majority of gas production in the Sultanate of Oman. The paper discusses a possibility of using the anomalies from natural radioactivity to evaluate the fracture height for complex tight gas in mature fields of Oman. The standard industry practice is adding radioactive isotopes to the proppant. Spectral Gamma Ray log is used to determine near wellbore traced proppant placement. Spectral Noise log in combination with Production logs helps to identify the active fractures contributing to production. These methods complement each other, but they are obviously associated with costs. Hence, majority of wells are fracced without tracers or any other fracture height diagnostics. However, in several brown fields, an alternative approach to identify fracture height has been developed which provides fit-for-purpose results. It is based on the analysis of naturally occurring radioactive minerals (NORM) precipitation. The anomalies were observed in the many gas reservoirs even in cases when tracers were not used. At certain conditions, these anomalies can be used to characterize fracture propagation and optimize future wells hydraulic Fracture design. A high number of PLTs and well test information were analyzed. Since tight formations normally don't produce without fracturing, radioactive anomalies flag the contributing intervals and hence fracture propagation. The main element of analysis procedure is related to that fact that if no tracers applied, the discrepancy between normalized Open Hole Gamma Ray and Gamma Ray taken during PLT after 6-12 months of production can be used instead to establish fracture height. This method cannot be applied for immediate interpretation of fracture propagation because time is required to precipitate NORM and using the anomalies concept. The advantage of this method is that it can be used in some fields to estimate the frac effectiveness of wells without artificial tracers. It is normally assumed that the Natural radioactivity anomalies appear mainly due to co-production of the formation water. However, in the fields of interest the anomalies appear in wells producing only gas and condensate. This observation provides an opportunity for active fracture height determination at minimum cost.

Applying Slim Dipole Sonic Tool to Evaluate Hydraulic Fracture Geometry and Orientation Using the Differential Sonic Method

Successful hydraulic fracturing is critical for hydrocarbon recovery from tight reservoirs. Fracture geometry is one essential quality indicator of the created fracture. The geometry provides information about the size of the created fracture and containment and verifies the pre-job modeling. Different techniques are applied to determine fracture geometry, and each has its own advantages and limitations. Due to its simplicity, the radioactive tracer log is commonly used to determine fracture placement and fracture height. Its main drawbacks include shallow depth of investigation, time dependency, and the requirement for multiple interventions for multistage fracturing operations. The crosswell microseismic technique probes a larger volume and it is potentially capable of providing fracture height, length, and orientation. Operational complexity and long processing turnaround time are the main challenges of this technique. Time-lapse shear slowness anisotropy analysis is an effective method to determine hydraulic facture height and orientation. In this technique, the shear slowness anisotropy is recorded before and after the fracture is created. The observed shear anisotropy difference indicates the intervals where the fractures were created, allowing these intervals lengths to be measured. Combining this analysis with gyroscopic data allows determining the fracture orientations. Compared to a tracer log, the differential casedhole sonic anisotropy (DCHSA) has a deeper depth of investigation, and it is time independent. Thus, the repeated log can be acquired at the end of the multistage fracturing operations. Compared to the microseismic technique, this new technique provides more precise fracture height and orientation. The new generation slim dipole sonic technology of 2.125-in. diameter extends the applicability of the DCHSA technique to smaller casing sizes. The shear differential method was applied to a vertical well that targeted the Athel formation in the south of the Sultanate of Oman. This formation is made of silicilyte and is characterized by very low permeability of about 0.01 md on average. Thus, hydraulic fracturing plays a critical role for the economic oil recovery in this reservoir. Aiming to achieve a better zonal contribution, the stimulation design was changed from a limited number of large fractures to an extensive multistage fracturing design in the subject well. Sixteen hydraulic fracturing stages were planned. The DCHSA was applied to provide accurate and efficient fracture geometry evaluation. The DCHSA accurately identified fracture intervals and their corresponding heights and orientations. This enabled effectively determining the created fracture quality and helped explain the responses of the production logs that were recorded during the well test. This study provided a foundation for the placement and completion design of the future wells in the subject reservoir. It particularly revealed adequate fracturing intervals and the optimum number of stages required to achieve optimum reservoir coverage and avoid vertical overlapping.

Connecting the Dots: Multistage Fracturing in Horizontal Wells with Multilayered Reservoirs - Lessons Learned

Efficient multistage hydraulic fracturing in horizontal wells in tight-gas formations with multilayered and laminated reservoirs is a very challenging subject matter; due to formation structure, required well trajectory, and the ability to establish a conductive and permanent connection between all the layers. BP Oman had initiated the technical journey to deliver an effective horizontal well multistage frac design through learnings obtained during three key pilot horizontal wells. Since these initial wells, additional candidates have been drilled and stimulated, resulting in further advancement of the learning curve. Many aspects will be covered in this paper, that will describe how to facilitate the most effective hydraulic fracture placement and production performance, under these laminated conditions. These approaches will include the completion and perforation selection, fracture initiation zone selection, fracture height consideration, frac fluid type and design. The paper will go on to describe a range of different surveillance options, including clean-up and performance surveillance as well as number of other factors. The experiences that have been gained provide valuable insight and learning about how to approach a multistage fracturing horizontal well program in this kind of depositional environment. Additionally, how these lessons can potentially be subsequently adapted and applied to access resources in the more challenging and higher risk areas of the field. For example, this paper will present direct comparison of over and under-displaced stages; differences in execution and production for cased hole and open hole completions; and many other variables that always under discussion for hydraulic fracturing in horizontal wells. This paper describes in detail the results of many multistage fracturing trials by BP Oman in horizontal wells drilled in challenging multilayered and laminated tight-gas reservoirs. These findings may help to cut short learning curve in similar reservoirs in the Middle East Region and elsewhere.

Integrated Hydraulic Fracture Geometry Evaluation Based on Pre-Cambrian Tight Silicylate Reservoir in South Oman Salt Basin

Pre-Cambrian South Oman tight silicilyte reservoirs are very challenging for the development due to poor permeability less than 0.1 mD and laminated texture. Successful hydraulic fracturing is a key for the long commercial production. One of the main parameter for frac planning and optimization is fracture geometry. The objective of this study was summarizing results comparison from different logging methods and recommended best practices for logging program targeting fracture geometry evaluation. The novel method in the region for hydraulic fracture height and orientation evaluation is cross-dipole cased hole acoustic logging. The method allows to evaluate fracture geometry based on the acoustic anisotropy changes after frac operations in the near wellbore area. The memory sonic log combined with the Gyro was acquired before and after frac operations in the cased hole. The acoustic data was compared with Spectral Noise log, Chemical and Radioactive tracers, Production Logging and pre-frac model. Extensive logging program allow to complete integrated evaluation, define methods limitations and advantages, summarize best practices and optimum logging program for the future wells. The challenges in combining memory cross-dipole sonic log and gyro in cased hole were effectively resolved. The acoustic anisotropy analysis successfully confirms stresses and predominant hydraulic fractures orientation. Fracture height was confirmed based on results from different logging methods. Tracers are well known method for the fracture height evaluation after hydraulic frac operations. The Spectral Noise log is perfect tool to evaluate hydraulically active fracture height in the near wellbore area. The combination of cased hole acoustic and noise logging methods is a powerful complex for hydraulic fracture geometry evaluation. The main limitations and challenges for sonic log are cement bond quality and hole conditions after frac operations. Noise log has limited depth of investigation. However, in combination with production and temperature logging provides reliable fit for purpose capabilities. The abilities of sonic anisotropy analysis for fracture height and hydraulic fracture orientation were confirmed. The optimum logging program for fracture geometry evaluation was defined and recommended for replication in projects were fracture geometry evaluation is required for hydraulic fracturing optimization.

Fracturing Height Growth Restriction Technique Successfully Extended into Horizontal Wells in Ostracod Formation

The Ostracod formation in the Awali brownfield is an extremely challenging layer to develop because the tight carbonate rock is interbedded with shaly streaks and because of the presence of a nearby water-bearing zone. Although the Ostracod formation has been in development since 1960, oil recovery has not yet reached 5% because past stimulation attempts experienced rapid production decline. The current project incorporated aggressive fracture design coupled with a unique height growth control (HGC) workflow, improving the development of Ostracod reserves. The HGC technology is a combination of an engineering workflow supported by geomechanical modeling and an advanced simulator of in-situ kinetics and materials transport to model the placement of a customized, impermeable mixture of particles that will restrict fracture growth. The optimized treatment design included injections of the HGC mixture prior to the main fracturing treatment. This injection was done with a nonviscous fluid to improve settling to create an artificial barrier. After the success of a trial campaign in vertical wells, the technique was adjusted for the horizontal wellbores. The high clay content within the Ostracod layers creates a significant challenge for successful stimulation. The high clay content prevents successful acid fracturing and leads to severe embedment with conventional proppant fracturing designs. We introduced a new approach to stimulate this formation with an aggressive tip-screenout design incorporating a large volume of 12/20-mesh proppant to obtain greater fracture width and conductivity, resulting in a significant and sustained oil production gain. The carefully designed HGC technique was efficient in avoiding fracture breakthrough into the nearby water zone, enabling treatments of up to 450,000 lbm to be successfully contained above a 20-ft-thick shaly barrier with small horizontal stress contrast. Independent measurements proved that the fracture height was successfully contained. This trial campaign in vertical wells proved that the combination of aggressive, large fracture designs with the HGC method could help unlock the Ostracod’s potential. Three horizontal wells were drilled and simulated, each with four stages of adjusted HGC technique to verify if this aggressive method was applicable to challenging sand admittance in case of transverse fractures. This rare implementation of HGC mixtures in horizontal wells showed operational success and proof of fracture containment based on pressure signatures and production monitoring. The applied HGC technique was modified with additional injections and improved by advanced modeling that only recently became available. These contributed to a significant increase of treatment volume, making the jobs placed in the Ostracod some of the world’s largest utilizing HGC techniques. The experience gained in this project can be of a paramount value to any project dealing with hydraulic fracturing near a water formation with insufficient or uncertain stress barriers.

Utilizing Microseismic to Monitor Fracture Geometry in a Horizontal Well in a Tight Sandstone Formation

This paper presents the use of real-time microseismic (MS) monitoring to understand hydraulic fracturing of a horizontal well drilled in the minimum stress direction within a high-temperature high-pressure (HTHP) tight sandstone formation. The well achieved a reservoir contact of more than 3,500 ft. Careful planning of the monitoring well and treatment well setup enabled capture of high quality MS events resulting in useful information on the regional maximum horizontal stress and offers an understanding of the fracture geometry with respect to clusters and stage spacing in relation to fracture propagation and growth. The maximum horizontal stress based on MS events was found to be different from the expected value with fracture azimuth off by more than 25 degree among the stages. Transverse fracture propagation was observed with overlapping MS events across stages. Upward fracture height growth was dominant in tighter stages. MS fracture length and height in excess of 500 ft and 100 ft, respectively, were created for most of the stages resulting in stimulated volumes that are high. Bigger fracture jobs yielded longer fracture length and were more confined in height growth. MS events fracture lengths and heights were found to be on average 1.36 and 1.30 times, respectively, to those of pressure-match.

Fracture Height Prediction Model Utilizing Openhole Logs, Mechanical Models, and Temperature Cooldown Analysis with Machine Learning Algorithms

Vertical wells require diagnostic techniques after minifrac pumping to interpret fracture height growth. This interpretation provides vital input to hydraulic fracturing redesign workflows. The temperature log is the most widely used technique to determine fracture height through cooldown analysis. A data science approach is proposed to leverage available measurements, automate the interpretation process, and enhance operational efficiency while keeping confidence in the fracturing design. Data from 55 wells were ingested to establish proof of concept.The selected geomechanical rock texture parameters were based on the fracturing theory of net-pressure-controlled height growth. Interpreted fracture height from input temperature cooldown analysis was merged with the structured dataset. The dataset was constructed at a high vertical depth of resolution of 0.5 to 1 ft. Openhole log data such as gamma-ray and bulk density helped to characterize the rock type, and calculated mechanical properties from acoustic logs such as in-situ stress and Young's modulus characterize the fracture geometry development. Moreover, injection rate, volume, and net pressure during the calibration treatment affect the fracture height growth. A machine learning (ML) workflow was applied to multiple openhole log parameters, which were integrated with minifrac calibration parameters along with the varying depth of the reservoir. The 55 wells datasets with a cumulative 120,000 rows were divided into training and testing with a ratio of 80:20. A comparative algorithm study was conducted on the test set with nine algorithms, and CatBoost showed the best results with an RMSE of 4.13 followed by Random Forest with 4.25. CatBoost models utilize both categorical and numerical data. Stress, gamma-ray, and bulk density parameters affected the fracture height analyzed from the post-fracturing temperature logs. Following successful implementation in the pilot phase, the model can be extended to horizontal wells to validate predictions from commercial simulators where stress calculations were unreliable or where stress did not entirely reflect changes in rock type. By coupling the geometry measurement technology with data analysis, a useful automated model was successfully developed to enhance operational efficiency without compromising any part of the workflow. The advanced algorithm can be used in any field where precise fracture placement of a hydraulic fracture contributes directly to production potential. Also, the model can play a critical role in cube development to optimize lateral landing and lateral density for exploration fields.