I am encouraged that we, as an industy, continue to refine and tweak our practices to solve zonal-isolation and cementing challenges in every well environment in which we work. As cementing techniques are improved, so, too, are the cement-evaluation methods and work flows. This paper demonstrates a new way to create gas-tight seals during well abandonment, overcoming the limitations of traditional methods and reducing the operator’s liability and potential environmental impact after decommissioning has been completed. This paper discusses shale creep and other shale-deformation mechanisms and how an understanding of these can be used to activate shale that has not contacted the casing yet to form a well barrier. Well RXY is located in Cairn’s Ravva offshore field in the Krishna-Godavari Basin in India.
PETRONAS FLNG SATU (PFLNG1) is a floating liquefied natural gas facility producing 1.2 million tonnes per annum (mtpa) of LNG, on a facility that is 365m long, and 60m wide, making it among the largest offshore facility ever built. The PFLNG1 project is the first of its kind in the world and is the first deployment of PETRONASâ€™ Floating Liquefied Natural Gas (FLNG) technology, consolidating the traditional offshore to onshore LNG infrastructure into a single facility. This will see a giant floating facility capable of extracting, liquefying and storing LNG at sea, before it is exported to customers around the globe. The FLNG journey has come a long way since 2006, with many technological options explored to monetise and unlock the potential of small and stranded gas fields. Moving an LNG production to an offshore setting poses a demanding set of challenges â€“ as every element of a conventional LNG facility needs to fit into an area roughly one quarter the size in the open seas whilst maintaining safety and increased flexibility to LNG production and delivery. The keynote address describes the breakthrough features of PFLNG1 â€“ the worldâ€™s first floating LNG facility; and the pioneering innovation that it brings to the LNG industry.
Berry, Sandra L. (Baker Hughes, a GE Company) | Palm, Dustin C. (Baker Hughes, a GE Company) | Usie, Marty J. (Baker Hughes, a GE Company) | Schutz, Ronald W. (TiCorr LLC) | Walker, Heath W. (Arconic Energy Systems)
Matrix acidizing treatments containing hydrogen fluoride (HF) acid have been utilized in stimulation treatments of offshore wells to remove skin associated with fines migration for many years. In the last few years, operators have moved toward the use of organic acid - HF acid treatments due to corrosion concerns in the downhole tubular strings during the initial pumping of live acid and in the Titanium Stress Joints (TSJ) during the acid flow back through the production riser. A corrosion inhibitor to inhibit any unspent HF in the acid flowback returns would be beneficial to operators. Production of spent acid flowing back through the production riser is seriously being considered because significant cost savings may be realized over other acid flowback options. However, although most HF acid systems are mostly and/or highly spent during the reaction time with the formation mineralogy, even small concentrations of remaining free HF in the spent acid returns can result in severe bore surface corrosion (etching) and byproduct hydrogen absorption by the riser system TSJ. Lab studies were performed with several different inhibitor formulations added to two different spent organic - HF acid fluid systems to determine the ability for these candidate inhibitors to thwart corrosion (etching) and corresponding hydrogen uptake on ASTM Grade 29 titanium (Ti-29) test coupons. These candidate inhibitors were subjected to four-hour exposure tests conducted at 170 F under 3500 psi pressure with various inhibitor concentrations to determine if the package could meet screening criteria of corrosion/etch rate of less than 0.5 mils per day (0.5 thousandths of an inch) and hydrogen uptake limits consistent with ASTM product specification limits for the short term exposure (i.e., four hours). These lab test results are compared to those from recent published lab test studies on titanium in live and spent HF containing acid fluids, along with discussion on practical implications and considerations for their field use. Developing a corrosion inhibitor to inhibit the residual HF acid in the spent flowback returns and prevent etching and hydrogen uptake by the TSJ in the production risers not only yields effective protection of the TSJ, allowing flowback fluids to be returned thru the production riser, but also offers a significant operational cost savings.
Haustveit, Kyle (Devon Energy) | Almasoodi, Mouin (Devon Energy) | Al-Tailji, Wadhah (CARBO Ceramics Inc.) | Mukherjee, Souvik (CARBO Ceramics Inc.) | Palisch, Terry (CARBO Ceramics Inc.) | Barber, Rusty (Formerly Devon Energy)
What is the number one problem with hydraulic fracturing and the frustrations that haunt every completions engineer? Our inability to see what is going on downhole during and after a hydraulic fracture stimulation job. This deficiency leads to numerous questions when attempting to optimize well performance and drainage, such as fracture extension, height growth, proppant/fluid volume usage, parent well depletion effects, cluster efficiency, etc. Over the years, several technologies have been used in an attempt to answer these questions including fiber optic, micro-seismic, chemical and proppant tracers, pressure matching and modeling. However, to date, none have been able to answer the most basic (and some would argue most important) question of all: where is the proppant located in the far-field?
A novel method that is gaining traction to answer this question is the use of electromagnetic (EM) technology to detect electrically conductive proppant. In this technology, a surface EM array is deployed and the EM field is measured both before and after the electrically-conductive proppant has been placed. Advanced modeling is then used to invert the before- and after-frac response to locate the proppant.
This paper will briefly review the technology as well as the motivation for deploying the process in one operator's STACK development. The paper will then thoroughly review a case history, where this EM proppant detection method was used in two offset infill wells in the STACK (Sooner Trend Anadarko Canadian and Kingfisher counties) play of Oklahoma. The two new wells were selected to be near the parent wellbore, where depletion effects were expected to impact both wells. The primary purpose of the project was to understand the impact the parent well had on an infill stimulation design.
Proppant maps will be presented which address the impact of the parent well depletion on the bi-wing fracture growth. Other complementary technologies will be presented including surface pressure monitoring of offset wells. This technology was also deployed previously in an area vertical science well and where applicable, these results will be included.
This paper will be useful for engineers, geoscientists and other technicians who wrestle with how to effective place their infill wells and design their fracture stimulations, with the goal of optimally depleting their acreage.
Several recent studies have found that proppant transport in the wellbore and through perforations plays a crucial role in ensuring uniform treatment distribution among all clusters in a plug-and-perf completion. Since most portions of a horizontal wellbore are undulating and not perfectly horizontal it is important to understand how proppants are transported in deviated wellbores. The objective of this study is to evaluate the effect of wellbore inclination on proppant transport in the wellbore and into perforation clusters.
Proppant transport through a perforation in a deviated wellbore was simulated by coupling computational fluid dynamics with a discrete element method (CFD-DEM). The wellbore inclination angle ranges from 0 (downward flow in a vertical wellbore) to 180 degrees (upward flow in a vertical wellbore), and three perforation orientations (high, low and side) are considered. A proppant transport efficiency (PTE) is defined to quantify the distribution of proppant into each perforation. The results for different well inclinations are compared with experimental data for validation. The validated model is then used to show the impact of well inclination on proppant placement.
Our results show that the effect of wellbore inclination on proppant placement varies for different perforation orientations. The wellbore inclination has a small effect for a side perforation. For low/high-side perforations, the corresponding proppant transport efficiency first increases/decreases when inclination angle increases from 0 to around 90 degrees (horizontal wellbore) and then decreases/increases when inclination angle further increases. Increasing wellbore flow rate, proppant concentration, fluid viscosity, or decreasing proppant size, proppant density reduces the impact of wellbore inclination. Simulation results also show that PTE reaches a maximum/minimum value when the well inclination is between 80 and 100 degrees for low/high-side perforations. The difference between proppant transport in a horizontal wellbore and a slightly deviated wellbore can be over 20% for low flow rates (< 2 bbl/min) and as low as 5% for high flow rates (> 40 bbl/min). This indicates that proppant inertia dominates proppant transport behavior in the heel-side clusters. The situation is reversed for toe- side clusters where inclination can play a crucial role in determining proppant transport into perforations. In addition, the effect of wellbore inclination becomes much more pronounced during a refracturing operation, where a large number of perforation clusters are open to flow.
This paper presents a novel method and new results to elucidate the effects of treatment design and wellbore inclination on proppant transport into perforation clusters. Results from this study provide a way for a completion engineer to use wellbore trajectory and treatment design information to estimate the distribution of proppant into each perforation cluster in fracturing and refracturing operations.
Manchanda, Ripudaman (The University of Texas at Austin) | Zheng, Shuang (The University of Texas at Austin) | Gala, Deepen (ExxonMobil Upstream Research Company) | Sharma, Mukul (The University of Texas at Austin)
Horizontal well fracturing is an established practice to improve the recovery of hydrocarbons from oil and gas reservoirs. To simulate fracture propagation, fracture closure during production and fracture reopening during fluid re-injection, it is essential to combine three important aspects of the problem: multiphase flow, geomechanics and fracture propagation. Current simulation software utilize separate models for these processes. Our objective in this paper is to present a streamlined workflow that we have developed to integrate these highly coupled processes into a single computationally efficient simulation model.
A fully coupled 3-D geomechanical reservoir simulator has been developed to perform multi-cluster hydraulic fracturing and reservoir simulations. The model (Multi-Frac-Res) uses coupled fluid and proppant transport in the fracture with multi-phase reservoir flow and reservoir stresses, in one system of equations. It also accurately models fluid and proppant distribution between multiple perforation clusters in the wellbore. Fracture closure during shut-in or production requires the use of implicit contact models and these models account for the impact of proppant embedment on fracture conductivity. The coupled system allows for seamless transition between fracture propagation, fracture closure, reservoir production and re-injection. This is done in one streamlined workflow without the need for inefficient transfer of information between different simulation software.
An effective hydraulic fracturing treatment aims at maximizing the EUR while maintaining high hydrocarbon production rates. The integrated model allows us to directly evaluate the impact of cluster spacing, frac fluid injection rate, proppant volume, and drawdown on the effectiveness of a hydraulic fracturing treatment. Simulation results are presented that show the relative importance of all the above parameters during the lifecycle of a typical horizontal well. We show how smaller cluster spacing can cause more interference between fractures and hamper the EUR. Larger proppant volume is shown to improve the conductivity of the created fractures and improve the productivity. Faster drawdown is shown to cause faster depletion and faster closure of the fracture but also helps in producing more fluid. Changes in the stress field around the fracture are presented and are shown to impact the growth of fractures in in-fill wells as well as the performance of refracturing treatments. These poroelastic effects are also shown to play a very important role in the growth and reorientation of fractures in injection wells during waterflooding.
Current simulation software utilize separate models for these processes leading to inefficient data transfer between several models that can cause loss of data. This study showcases an integrated model that can simulate the lifecycle of hydraulically fractured wells all the way from creation of the hydraulic fractures to production and reinjection and allows for a holistic comparison between scenarios by comparing productivity numbers and EUR estimates.
Seth, Puneet (The University of Texas at Austin) | Manchanda, Ripudaman (The University of Texas at Austin) | Elliott, Brendan (Devon Energy) | Zheng, Shuang (The University of Texas at Austin) | Sharma, Mukul (The University of Texas at Austin)
During stimulation in a treatment well, offset well pressure measurements resulting from stress-shadow related interference are often used to estimate hydraulic fracture geometry. Current pressure interference models typically assume one dominant fracture per stage in their analysis, which is an overly simple assumption and can result in erroneous estimates of hydraulic fracture geometry. This stems from the limited capability of existing models which are not equipped to interpret multi-cluster fracture propagation scenarios. In this study, we present workflows to analyze dynamic pressure time-series responses observed at offset monitor wells during injection in a nearby treatment well, to diagnose multi-cluster fracture propagation.
A fully-coupled, 3-D, reservoir-fracturing simulator which models hydraulic fractures explicitly as compliant discontinuities has been used to simulate pressure interference in multi-well pads. We model dynamic fracture propagation from multiple clusters in the treatment well and analyze the corresponding pressure changes observed at an offset monitor well. We apply our dynamic pressure transient analysis model to analyze multi-cluster fracture propagation from the treatment well and contrast it with a scenario that assumes one dominant fracture per stage. We show that the simulated offset pressure response during the propagation of one dominant fracture per stage is very different compared to a multi-cluster propagation.
We analyze the dynamic intra-stage offset well pressure signatures (inflections in the pressure response, slope of the pressure response, arrival times etc.) to develop workflows to test diversion effectiveness and provide insights on optimum job volumes, in a relatively inexpensive manner. We show the impact of completion design and perforation erosion on the offset well pressure response. We test different cluster designs and analyze the offset well pressure response in each case to quantify cluster efficiency. We apply our dynamic pressure interference testing model to field data from the Permian Basin to test for diversion effectiveness and diagnose dominant cluster variability during stimulation.
Well-to-well interference is an increasingly discussed issue. Previously drilled and producing “parent” wells and recently drilled “child” wells are yielding a reduction in recovery rates in both short and long-term cases due to interference. A primary contributor to the variability in production is the presence of pressure sinks as the result of production depletion in the parent wells. Infill drilling will continue to occur in the development of unconventional plays, and it is crucial to gain an understanding of the impacts of well-to-well interference on hydraulic fracture generation.
This paper discusses a detailed approach to investigating well-to-well interference based on integrating hydraulic fracture modeling and reservoir simulation in two different formations, the Niobrara and Codell, in the Denver-Julesburg Basin. The geomechanical properties were calibrated by DFIT data and pressure matching of the parent well treatments. The resulting parent well fracture geometries were incorporated into a numerical reservoir model to determine the pressure depletion envelopes. The imported depletion model allows for the simulation of the child well treatments and associated impacts of the pressure sinks on fracture generation and the interaction between child and parent wells. The resulting depletion model provided a framework to investigate various methods to mitigate the effects of well-to-well communication in subsequent development. The developed workflow of well-to-well interference is applicable in understanding the effects of infill development in other producing basins.
The modeled child well treatments resulted in a clear indication of well-to-well communication with the parent wells that was attributable to pressure depletion. Actual field bottom-hole pressure measurements validated these results in the parent wells captured during the time of the child well treatments. Resulting proppant concentrations of the child well fractures indicated that the majority of the proppant transports towards the parent wells. Very little effective conductivity exists in the opposing direction of the depleted regions.
Slickwater treatment simulations indicate extremely asymmetric fractures that stay isolated to their respective target bench. For child wells in the same bench as the parent wells, fractures propagate directly toward the parent wells, with little to no fracture growth in the opposite direction.
Protection frac simulations indicate beneficial or detrimental results depending on the amount of repressurization that is achieved and the distance that the pressure transient extends into the reservoir. Re-pressurizing the reservoir surrounding the parent wells by 1,000 psi resulted in a reduction of well interference. A 500-psi scenario resulted in increased well interference between the parent wells. Several wells communicated with both parent wells due to the repressurization being insufficient to offset the depletion.
Natural repressurization of the reservoir to mitigate the effect of well interference was also investigated by using the reservoir model. Simulation of the parent wells being shut-in for three months prior to the child well treatments resulted in a pore pressure increase of only 280 psi. Based on the protection frac sensitivity of 500 psi, this is not a large enough repressurization to mitigate well-to-well interference successfully in the modeled scenarios.