Many techniques have been used to model, diagnose and detect fracture dimension and propagation during hydraulic fracturing. Diagnosing fracture dimension growth vs time is of paramount importance to reach the desired geometry to maximize hydrocarbon production potential and prevent contacting undesired fluid zones. The study presented here describes a technique implemented to control vertical fracture growth in a tight sandstone formation being stimulated near a water zone. This gas well was completed vertically as openhole with Multi- Stage Fracturing (MSF). Pre-Fracturing diagnostic tests in combination with high-resolution temperature logs provided evidence of vertical fracture height growth downward toward water zone. Pre-fracturing flowback indicated water presence that was confirmed by lab test. Several actions were taken to mitigate fracture vertical growth during the placement of main treatment. An artificial barrier with proppant was placed in the lower zone of the reservoir before main fracturing execution. The rate and viscosity of fracturing fluids were also adjusted to control the net pressure aiming to enhance fracture length into the reservoir. The redesigned proppant fracturing job was placed into the formation as planned. Production results showed the effectiveness of the artificial lower barrier placed to prevent fracture vertical growth down into the water zone. Noise log consists of Sonic Noise Log (SNL) and High Precision Temperature (HPT) was performed. The log analysis indicated that two major fractures were initiated away from water-bearing zone with minimum water production. Additionally, in- situ minimum stress profile indicated no enough contrast between layers to help confine fracture into the targeted reservoir. Commercial gas production was achieved after applying this stimulation technique while keeping water production rate controlled within the desired range. The approach described in this paper to optimize gas production in tight formation with nearby water contact during hydraulic fracturing treatments has been applied with a significant improvement in well production. This will serve as reference for future intervention under same challenging completion conditions.
Production logging in horizontal wells presents particular challenges, especially when they are completed uncemented using prepacked screens or slotted liners. These challenges are attributed to well geometry, i.e., the existence of severe doglegs and undulations, where trapped fluids that could directly affect and influence data readings from the tools, such as stagnant water, may lie either inside or outside the liner in low areas at the bottom of the well, or stagnant gas that may accumulate on the high side of drain-hole undulations.Considering the challenges mentioned above, an integrated horizontal multiphase production logging tool (IHMPLT) is usually required, and in many cases this tool needs to be complimented with a pulsed neutron logging tool (PNLT) to have a more accurate reading of fluid entries.Over the last 20-years, coiled tubing (CT) equipped with electric cable has been widely used to conduct production logging in horizontal wells, and more recently, CT equipped with an optical fiber has eliminated the restrictions associated with CT equipped with electric cable while enabling several advantages, such as distributed temperature sensing (DTS) to compliment production profiles from IHMPLT. The previous system was unable to run PNLT. To tackle the above described limitations, and having a more robust portfolio of production logging available, a new solution of real-time downhole measurements via CT equipped with fiber optics has been introduced to enable real-time data acquisition of DTS, IHMPLT, and PNLT logs.This paper discusses the case history of this first worldwide application. It also provides lessons learned and perspectives for this technology.
Well completion practices in high-temperature, high-pressure carbonates are challenging especially for long lateral horizontal wells intended for fracturing applications. An integrated approach involving intervention and fracturing design and reliable post-fracturing flow measurements is very critical to optimize the well performance. After initial intervention complexities due to wellbore accessibility in a 6,250-ft cemented lateral initially planned with 13 fracturing stages resulting in the loss of many operational days, a revamped engineering workflow was planned for Well-A. As a first step, Coiled Tubing (CT) was used for abrasive jetting perforations, cleanout, and acid squeeze functionalities with a novel bottomhole assembly (BHA). The BHA was equipped with a real-time telemetry to optimize intervention to a single run. Having real-time bottomhole parameters helped in perforating the desired zones accurately and enhanced the injectivity by creating cleaner perforation tunnels. Stages were reduced to five with an optimized perforation design based on rock typing approach, and short clusters were designed to divert the fracture fluids effectively using multimodal particulate diversion. Each fracturing stage was isolated with a mechanical plug. A novel high-frequency pressure monitoring technique that analyzes fluid entry points from water hammers was utilized during the fracturing treatments to analyze on-the-fly diversion efficiency and optimize further treatments. A multiphase flowmeter was utilized to enhance milling and flowback to minimize losses and manage the choke schedule based on actual well performance leading to better fracture cleanup and recovery. The production performance of Well-A was compared with two offset horizontal wells drilled azimuthally parallel, intersecting the same carbonate sublayer. The post-fracturing absolute production enhancement analysis showed 11 to 15% improvement, and productivity index (PI) improvement was 40 to 63% when normalized by stage count. The effective integration of multiple technologies was applied successfully on the candidate well, yielding enhanced operational efficiency with optimized production performance.
The design of fracture diversion in tight carbonates has been a challenging problem. Recently, a conceptual and theoretical workflow was presented using a β diversion design parameter that uses system volumetric calculations based on high-fidelity modeling and mathematical approximations of the etched system. A robust field validation of that approach and near-wellbore diversion modeling was conducted to extend the application. Extensive laboratory and yard-scale testing data were utilized to realize the diversion processes. Fracture and perforation modeling coupled with fracture diagnostics was used to define system volumetrics, defined as the volume where the fluid needs to be diverted away from. Multimodal particulate pills were used based on a careful review of the size distribution and physical properties. Bottomhole reactions and post-fracturing production for multiple wells and 100 particulate pills were studied to see the effect of the β factor on diversion and production performance. A multiphysics near-wellbore diversion model was used for the first time to simulate the pill effect. Representative wells were selected for the validation study; these included vertical and horizontal wells and varying perforation cluster design, stages, and acid treatments. A complex problem was solved with reaction modeling coupled with near-wellbore diversion for the first time based on given lithology and pumped volumes to match the treatment and diversion differential pressures. Final active fractures and stimulation efficiency were computed through etched geometry. The results showed a range of etched fracture length from 86 to 109 ft and width of 0.05 to 0.08 in. A similar approach was used for perforation system analysis. Diversion pills from 2 to 15 per well were investigated with a 5- to 12-bbl particulate diversion pill range. Finally, the β factor was calculated for each case based on the diversion material and system volumetric ratio. The parameter was plotted against the average diversion pressure achieved and showed an R2 of 0.87. Based on the comprehensive theoretical, numerical modeling, and field-coupled findings, a β factor of 0.8 to 1.0 is recommended for optimum diversion and production performance. For multiple cases, stimulation efficiency and production performance have been enhanced up to 200%. From the field results, it is evident that the design of near-wellbore diversion needs to be strategic. The unique diversion framework provides the basis for such a well- and reservoir-specific strategy. Proper and scientific use of diversion material and modeling can lead to advances in overall project management by optimizing the cost–efficiency–quality project triangle. Digital advancements with digitized cores, fluid systems, and advanced modeling have significant potential for the engineered development of tight carbonates.
Tight carbonate development is moving towards longer laterals requiring a higher number of fracturing stages to complete a given well. A higher stage count implies longer completion time and higher costs. Therefore, an engineered strategy using technology enablers is indispensable to reducing the number of stages while retaining the well performance objective. A 6,250-ft cemented lateral initially planned with 13 fracturing stages was analyzed for lithology and reservoir development to revise the perforation strategy to complete with more clusters per stage and reduced the number of stages to 5 stages. Clusters were designed to be very narrow to effectively divert the fracture fluids using chemical diversion. For a successful stimulation evaluation, a novel pressure monitoring technique was used to analyze the fluid entry points from the water hammers. Pills of multimodal particulate near-wellbore diverters were used across the lateral to stimulate the perforated clusters in only five fracture stages effectively. The multimodal particle distribution model allows for bridging and then creating an impermeable flow barrier to ensure diversion. Effective diversion was seen through a pressure increase when diverter entered the formation. Correlations were analyzed for diversion pressure dependence on pill volume and injection rate to improve diversion. A new algorithm for nonintrusive diagnostics was also deployed. The algorithm combines advanced signal processing with a tube wave velocity model based on Bayesian statistics and has no additional operational footprint. The program allowed a timely interpretation to evaluate the fluid entry points based on the water hammer events. This evaluation was compared to the intuitive stimulation sequence based on the lithology to explain the results. The comprehensive analysis demonstrated the lateral was stimulated effectively. Finally, the production performance was compared with two offset horizontal wells intersecting the same carbonate sublayer. Offset 1 was a cemented lateral completed with 12 stages, and offset 2 was an openhole packer and sleeve lateral completed with 7 stages. Analysis of the post-fracturing absolute production enhancement showed 11 to 15% improvement and production index (PI) improvement was 40 to 63% when normalized by stage count. The paper presents a rare and unique strategic integration of multiple technologies. This success paves the way for similar future developments to enhance operational efficiency and allow significant cost savings.
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