The Mungo Field is a medium-sized oil field with a primary gas cap located in the Central North Sea. It has been developed as part of the Eastern Trough Area Project (ETAP) via a Normally Unmanned Installation (NUI) which is positioned directly above the field, with production tied back ca. 20 km to the ETAP Central Processing Facility (CPF).
Hydrocarbons are trapped in a pierced four-way dip closure against the Mungo salt diapir. The principal reservoir of the Mungo field is the steeply-dipping Palaeocene sands of the Sele, Lista and Maureen Formations, which overlie the Ekofisk, Tor and Hod Formations of the Chalk Group. The Palaeocene sandstone reservoir has been developed under combined water and gas injection since 1998. The underlying tight Chalk reservoir contains a poorly understood but potentially very substantial oil resource (estimated at 30 – 300 MM.bbls STOIIP). Direct development of the Chalk within the Mungo field has been very limited to date, with little offtake and few completions.
There have been a number of key challenges to overcome in order to demonstrate that the Chalk can be efficiently developed on Mungo. These challenges include the ability to achieve economic well production rates combined with demonstrable recovery of oil from the low permeability chalk matrix, given that there is very little evidence of natural fracturing. This is most accurately described in the definition and selection of an appropriate and efficient completion approach; a process and case history which this paper will fully detail. There are several features that make development of the Mungo Chalk both appealing and compelling, including the proximity/connection to existing infrastructure (with reducing throughput) and penetration of the Chalk by some existing Mungo development wells. This combination offers a unique potential suite of opportunities for low cost intervention, appraisal and subsequent development via recompletion.
In 2015, BP performed a Chalk appraisal test in an existing Mungo producer, W169 (22/20-A19), including the pumping of two distinct acid fracturing stages, a flow-back/clean-up, stable rate well-test and a long term shut in for a PBU. The W169 well was selected as the candidate well, as it intersected 220 m of the chalk sequence, including the Hod, Tor and Ekofisk formations. This paper presents the full sequence and details of this Mungo Chalk reservoir evaluation process. The information provided will describe the approaches taken to the design, the planning and the execution of cost-effective stacked, multi-zone acid-fracturing operations. Finally, the paper will close-out with the results of the operations and post job analysis, and provide an overview of future potential that has been unlocked by this sequence of operations.
Manchanda, Ripudaman (The University of Texas at Austin Philip Cardiff, University College Dublin) | Bryant, Eric C. (The University of Texas at Austin Philip Cardiff, University College Dublin) | Bhardwaj, Prateek (The University of Texas at Austin Philip Cardiff, University College Dublin) | Sharma, Mukul M. (The University of Texas at Austin)
Increasing the efficiency of completions in horizontal wells is an important concern in the oil and gas industry. To decrease the number of fracturing stages per well it is common practice to use multiple clusters per stage. This is done with the hope that most of the clusters in the stage will be effectively stimulated. Diagnostic evidence, however, suggests that in many cases only 1 or 2 clusters out of 4 or 5 clusters in a stage are effectively stimulated.
In this paper strategies to maximize the number of effectively stimulated perforation clusters are discussed. A fully 3-D poroelastic model that simulates the propagation of non-planar fractures in heterogeneous media is developed and used to model the propagation of multiple competing, fractures. A parametric study is first conducted to show how important fracture design variables such as limited entry perforations and cluster spacing; and formation parameters such as permeability, lateral and verical heterogeneity affect the growth of competing fractures. The effect of stress shadowing due to both mechanical and poroelastic effects is accounted for.
3-D numerical simulations have been performed to show the impact of some operational and reservoir parameters on simultaneous competitive fracture propagation. It was found that an increase in stage spacing decreases the stress interference between propagating fractures and increases the number of propagating fractures in a stage. It was also found that an increase in reservoir permeability can decrease the stress interference between propagating fractures because of poro-elastic stress changes. A modest (about 25%) variability in reservoir mechanical properties along the wellbore is shown to be enough to alter the number of fractures created in a hydraulic fracturing stage and mask the effects of stress shadowing. Inter-stage fracture simulations show post-shutin fracture extension induced by stress interference from adjacent propagating fractures. The impact of poro-elasticity is highlighted for infill well fracture design and preferential fracture propagation towards depleted regions is clearly observed in multi-well pad fracture simulations.
The results in this paper attempt to provide practitioners with a better understanding of multi-cluster fracturing dynamics. Based on these findings recommendations are made on how best to design fracture treatments that will not only lead to the successful placement of fluid and proppant in a single fracture, but in a set of fractures that are competing with each other for growth. The ability to successfully stimulate all perforation clusters is shown to be a function of key fracture design parameters.
Narasimhan, Santhosh (Sanjel Corporation) | Shaikh, Hamza (Sanjel Corporation) | Gray, James K. (Sanjel Corporation) | Cherian, Bilu V. (Sanjel Corporation) | Olaoye, Olubiyi (Sanjel Corporation) | Rifai, Rafif (Sanjel Corporation) | Kublik, Kristina (Sanjel Corporation) | McCleary, Matt (SM Energy) | Fluckiger, Samuel D. (SM Energy) | Sharf-Aldin, Munir (MetaRock Laboratories Inc)
This paper covers the methodology to derive all geomechanical properties (Young's modulus, Poisson's ratio and vertical/horizontal variable Biot constants as a function of rock type) for 13 different stress models. Minimum horizontal stress (Sh) is a key parameter controlling fracture height growth during hydraulic fracturing simulation. Assuming a homogeneous formation (rock property Horizontal:Vertical = 1.0) or poorly derived inputs for the anisotropy model can lead to incorrect fracture geometry. A major assumption made using the various stress models is the Biot poro-elastic constant. Many default models assume a Biot poro-elastic constant of one, which is valid for coarse grained conventional reservoirs where porosity is greater than 20%. Most of the reservoirs stimulated with hydraulic fracturing today do not fall in that porosity range, therefore an alternative derivation for the Biot poro-elasticity and its variability requires additional discussion.
Models derived and compared with their associated uncertainties in this paper include: Ben Eaton – isotropic, anisotropic, dynamic and modified with correction factor; default from auto log calibration; Vernik, Jaeger & Cook; Hubbert & Willis; Thiercelin – MC envelope and stiffness tensors (Cij); Segall & Penebaker. The geomechanical properties from the different stress models noted above were inserted into a gridded fracturing simulator. The outputs were compared to actual job and calibration data for; minimum horizontal stress, end of job net pressure and fracture geometry for each of the models.
When comparing fracture geometries from each stress model against calibration data it is apparent that the chosen stress model will have a substantial influence on the result. This illustrates the importance of choosing the correct stress model for fracture simulations.
Typical hydraulic fracturing designs in shale utilize a predetermined fluid pump rate, which once achieved is held constant throughout the treatment, excluding situations when surface pressure limitations or other conditions disallow. We propose a method of pumping hydraulic fracture stages where the fluid pump rate is rapidly changed from the predetermined maximum rate, to some significantly lower rate, and then rapidly increased back to original maximum rate. This rapid change in the flow rate produces a pressure pulse that travels up and down the wellbore and has the capacity, together with the pump rate change, to open previously unopened perforations, while increasing fracture complexity through fluid diversion.
We observed increased microseismicity during hydraulic fracturing in stages with frequent pump rate changes. Regardless of their type and nature, seismic signals are indicative of fragmentation of the treated zone. This could be from shear shattering or dilatational opening. One can also assume that high signal density is a good measure of fracturing efficiency. To further investigate these observations, we implemented a variable pump rate fracture design in a Marcellus shale well. More specifically, we implemented the variable pump rate frac design in every odd stage, while implementing a constant rate design in every even stage. This was done in order to account for changes in the reservoir along the horizontal lateral.
Production log results showed on average a 19% increase in production for the variable pump rate stages versus the constant pump rate stages. A lower treating pressure was often encountered after the rapid rate changes, leading to the conclusion that unopened perforations were opened with the aid of the induced pressure pulses. Total well production decline was much slower for test well that included variable pump rate changes versus the offset horizontal well which did not include the variable pump rate frac design.
And finally water hammer frequency decay analysis shows a predictable trend in well with variable pump rate stages. Throughout the variable pump rate stages, no proppant transport issues were encountered and the frac stages were completed without any major issues.
Rapid rate changes applied throughout the fracture treatment enhance microseismicity, which could be interpreted as additional fracture complexity. Surface fracturing pressure data shows that rapid pump rate changes open additional perforations without physical flow diverters such as ball sealers or frac balls, while production log data shows higher production. Implementation of the Variable Rate hydraulic fracturing method results in no additional costs while it increases stimulation efficiency.
Microseismic mapping during hydraulic fracturing processes in Vaca Muerta (VM) Shale in Argentina shows a group of microseismic events happening at shallower depth and at later injection time, and they clearly deviate from the growing planar hydraulic fracture. This spatial and temporal behavior of these shallow microseismic events incurs some questions regarding the nature of these events and their connectivity to the hydraulic fracture. To answer these questions, in this paper, we investigate these phenomena using a true 3D fracture propagation modeling tool along with statistical analysis on the properties of microseismic events.
First, we propose a novel technique in Abaqus incorporating fracture intersections in true 3D hydraulic fracture propagation simulations based on pore-pressure Cohesive Zone Model (CZM). The simulations fully couple slit flow in fracture with poro-elasticity in matrix and continuum-based leak-off on the fracture walls, and honor the fracture tip effects in quasi-brittle shale. Using this model, we quantify vertical natural fracture activation depending on reservoir depth, fracturing fluid viscosity, mechanical properties of the natural fracture cohesive layer, natural fracture conductivity, and horizontal stress contrast. The modeling results demonstrate this natural fracture activation in coincidence with the hydraulic fracture growth complexities at the intersection such as height throttling, sharp aperture reduction after the intersection, and multi-branching at various heights and directions.
Finally, we investigate the hydraulic fracture intersection with a natural fracture in the multi-layer VM Shale. We infer the natural fracture location and orientation from the microseismic events map and Formation MicroImager log in a nearby vertical well, respectively. We integrate the other field information such as mechanical, geological, and operational data to provide a realistic hydraulic fracturing simulation in the presence of a natural fracture. Our 3D fracturing simulations equipped by the new fracture intersection model rigorously simulate the growth of a realistic hydraulic connection path toward the natural fracture at shallower depths, which was in agreement with our microseismic observations.
A modeling framework is developed to describe proppant transport (including gravitational settling and tip-screen out) in a hydraulic fracturing simulator that can function as either fully-3D or pseudo-3D. The simulator locally enforces mass balance of fluid and proppant and applies appropriate boundary conditions for mechanical calculations. The simulator uses recently developed constitutive equations that smoothly capture the transition from Poiseuille flow to Darcy flow as the proppant concentration transitions from a dilute mixture to a packed bed. We develop new constitutive relations that enable the model to describe fracture closure against proppant (at either low or high concentration) after the end of injection. We also develop a framework for modeling proppant settling in a pseudo-3D model. The method ensures a continuous solution, which guarantees convergence and accuracy with refinement of the temporal and spatial discretization. The framework allows proppant to settle into a proppant bank at the bottom of the fracture. The proppant bank can grow, remain stationary, or erode, depending on flow conditions. The simulator can describe tip-screen out (TSO) and the tendency for the volumetric flowing fraction of proppant to exceed the volumetric fraction of proppant due to the tendency of proppant to flow at the center of the fracture aperture. Pseudo-3D simulations are compared to the fully-3D simulations for both hydraulic fracturing and long-term production. For hydraulic fracturing, the pseudo-3D simulations are able to substantially reproduce the results from the fully-3D simulations and are far more computationally efficient. The simulation methods are compared using a variety of values for proppant size, fluid viscosity, and proppant density. An optimized proppant schedule is tested in order to improve horizontal proppant placement and prevent excessive tip screen-out. The simulations indicate that because fracture closure can be slow in very low permeability formations, substantial settling occurs after the end of injection, significantly worsening vertical proppant placement. For simulation of long-term production, the pseudo-3D results deviate strongly from the fully-3D simulations, indicating that the pseudo-3D model is not suitable for simulating the production phase, as currently formulated.
Acid fracturing stimulation can be an effective means to improve well performance in carbonate formations. In general, a treatment consists of multiple stage injections alternating between acid and non-reacting fluid to better place acid, and therefore, to create sustainable conductivity for enhanced well productivity. Selecting appropriate fluid systems is critical in success of acid fracturing. To optimize acid fracturing design, an integrated approach is needed to model the fluid behavior inside of the fracture, the conductivity after fracturing, and the productivity of fractured wells.
The integrated approach includes an acid transport model and a fracture propagation model. Theoretical models were developed to obtain the conductivity distribution and acid penetration distance inside fractures. Continuity and momentum balance equations are solved in three-dimensional space for pressure and velocity profiles. Once the velocity profile is generated, the acid balance equation can be solved for the acid concentration profile. Obtaining a concentration profile helps in calculating the amount of rock etched through diffusion and convection. Conductivity distribution is calculated using a correlation where statistical parameters are used to account for fracture heterogeneity. Finally, a reservoir simulator is used to predict the production performance from acid fractured wells.
Straight, emulsified, and gelled acid systems are examined using the integrated approach to capture the effect of each on fracture conductivity and acid penetration distance. Optimizing these two parameters will improve the production performance significantly. Straight acid reacts aggressively with carbonate formations and leaks off significantly more near the entrance of the fracture when compared with the other two acid systems. The apparent viscosities of gelled or emulsified acids are substantially higher than that of straight acid, and the diffusion coefficients of these viscous fluids are substantially lower than that of straight acid. These properties result in deeper penetration down the fracture with gelled or emulsified acids, but also less fracture etching by acid near the well. The tradeoff between deeper penetration with viscosified acid systems versus more near well etching with less viscous systems means that the acid formulation can be optimized depending primarily on the formation permeability.
Production analysis of these three acid systems suggests that emulsified acid is better used in tight formations. Gelled acid, on the other hand, results in the highest production rate when used in relatively high to medium permeability formations. Straight acid is the preferred system only when short, highly conductive fractures are desired.
The objective of achieving uniform stimulation of a reservoir through hydraulic fracturing from a horizontal well typically depends upon the ability to generate a uniform array of hydraulic fractures from multiple entry points. However getting all the hydraulic fractures in an array to grow simultaneously is a challenge. The challenge apparently arises not only due to reservoir variability, but also in a substantial part due to the stress interaction among growing hydraulic fractures. This phenomenon, referred to as a stress shadowing, inhibits the growth of inner fractures and favors the growth of outer fractures in the array. Recently, we created a new hydraulic fracture simulator which simulates the growth of an array of hydraulic fractures in 10-6–10-5 of the computation time required for fully coupled 3D simulations of multiple parallel planar hydraulic fracture growth. Using a novel energetic approach to account for the coupling among the hydraulic fractures and through judicious use of asymptotic approximate solutions, the simulation enables designs reducing the negative effects of stress shadow by balancing the interaction stresses through non-uniform perforation cluster spacings. Furthermore, so-called limited entry approaches are thought to be capable of promoting greater uniformity among simultaneously growing hydraulic fractures as long as the number and diameters of the perforations in each cluster are appropriately designed. In order to enable such optimizations and designs, we add perforation loss into to the approximate, energy-based simulator. Our results show the potential of choosing the proper perforation diameter and number to double the fracture surface area generated by a given injected fluid volume though minimizing the negative effect of interaction. The usefulness of the new simulator is demonstrated by development of example limited entry designs and optimal spacings for different numbers of entry points.
Microseismic monitoring of hydraulic fracturing in unconventional reservoirs is a valuable tool for delineating the effectiveness of stimulations, completions, and overall field development. Important information, such as fracture azimuth, fracture length, height growth, staging effectiveness, and many other geometric parameters, can typically be determined from good quality data sets. In addition, there are parameters now being extracted from microseismic data sets, or correlated with microseismic data, to infer other properties of the stimulation/completion system, such as stimulated reservoir volume (SRV), discrete fracture networks (DFNs), structural effects, proppant placement, permeability, fracture opening and closure, geohazards, and others. Much of the information obtained in this way is based on solid geomechanical or seismological principles, but some of it is speculative as well.
This paper reviews published data where microseismic results have been validated by experiments using some type of ground-truth or alternative measurement procedure, discusses the geomechanics and seismological mechanisms that can be reasonably considered in evaluating the likelihood of inferring given properties, and appraises the uncertainties associated with monitoring and the effect on any inferences about fracture behavior. Considerable data now exist from tiltmeters, fiber-optic sensing, tracers, pressure sensors, multi-well-pad experiments, and production interference that can be used to aid the validation assessment.
Relatively limited microseismic results have actually been validated in any consistent manner. Fracture azimuth from microseismic has been verified across a wide range of reservoir types using multiple techniques. Good validation of fracture length and height were performed in sandstones for planar fractures; fracture length and height in typical horizontal completions with multiple fractures or complexity have a lesser degree of verification. Other parameters, such as complexity, discrete fracture networks, source parameters, and SRV, have little supporting evidence to provide validation, even though they might have sound physical principles underlying their application. It is clear that microseismic monitoring would benefit from more attention to validation testing. In many cases, the data might be available but have not been used for validation purposes, or such results have not been published.
A sudden change in flow in a confined system results in the formation of a series of pressure pulses known as a water hammer. Pump shutdown or valve closure at the conclusion of a hydraulic fracture treatment frequently generates a water hammer, which sends a pressure pulse down the wellbore that interacts with the created fracture before returning towards the surface. The result is a pressure profile that consists of a series of oscillations that attenuate over time due to friction. Hydraulic fracture treatments have been shown to alter the period, amplitude, and duration of the water hammer signal. The goal of this study was to history match water hammer data from several multi-stage fractured wells with simulations derived from a water hammer model and compare the results to gathered production log and microseismic derived stimulated reservoir volume (SRV) data.
Water hammer pressure signals were simulated in this study with a numerical model that combined the continuity and momentum equations of the wellbore with a created hydraulic fracture represented by a circuit with a resistance, capacitance, and inertance (
It is shown that the water hammer derived capacitance was directly correlated with the stimulated reservoir volume (SRV) derived from micro-seismic measurements, however, it showed no correlation with gas production obtained from the production log. Inertance also showed a positive correlation with SRV but had no correlation with production log data. Finally, the water hammer derived resistance exhibited no correlation with SRV data, but showed a positive correlation with gas production.
The results from this work support the fact that the water hammer signal at the conclusion of a hydraulic fracturing treatment stage, contains diagnostic information about the created fracture network. Since this data can be recorded at very little incremental cost, it may prove to be a very useful and cost effective fracture diagnostic tool.