Gaol, Calvin (Clausthal University of Technology) | Wegner, Jonas (Clausthal University of Technology) | Ganzer, Leonhard (Clausthal University of Technology) | Dopffel, Nicole (BASF SE) | Koegler, Felix (Wintershall Holding GmbH) | Borovina, Ante (Wintershall Holding GmbH) | Alkan, Hakan (Wintershall Holding GmbH)
Utilisation of microorganisms as an enhanced oil recovery (EOR) method has attracted much attention in recent years because it is a low-cost and environmentally friendly technology. However, the pore-scale mechanisms involved in MEOR that contribute to an additional oil recovery are not fully understood so far. This work aims to investigate the MEOR mechanisms using microfluidic technology, among others bioplugging and changes in fluid mobilities. Further, the contribution of these mechanisms to additional oil recovery was quantified.
A novel experimental setup that enables investigation of MEOR in micromodels under elevated pressure, reservoir temperature and anaerobic and sterile conditions was developed. Initially, single-phase experiments were performed with fluids from a German high-salinity oil field selected for a potential MEOR application: Brine containing bacteria and nutrients was injected into the micromodel. During ten days of static incubation, bacterial cells and in-situ gas production were visualised and quantified by using an image processing algorithm. After that, injection of tracer particles and particle image velocimetry were performed to evaluate flow diversion in the micromodel due to bioplugging. Differential and absolute pressures were measured throughout the experiments. Further, two-phase flooding experiments were performed in oil wet and water wet micromodels to investigate the effect of in-situ microbial growth on oil recovery.
In-situ bacteria growth was observed in the micromodel for both single and two-phase flooding experiments. During the injection, cells were partly transported through the micromodel but also remained attached to the model surface. The increase in differential pressure confirmed these microscopic observations of bioplugging. Also, the resulting permeability reduction factor correlated with calculations based on the Kozeny-Carman approach using the total number of bacteria attached. The flow diversion of the tracer particles and the differences in velocity field also confirmed that bioplugging occurred in the micromodel may lead to an improved conformance control. Oil viscosity reduction due to gas dissolution as well as changes in the wettability were also identified to contribute on the incremental oil. Two-phase flow experiments in a newly designed heterogeneous micromodel showed a significant effect of bioplugging and improved the macroscopic conformance of oil displacement process.
This work gives new insights into the pore-scale mechanisms of MEOR processes in porous media. The new experimental microfluidic setup enables the investigation of these mechanisms under defined reservoir conditions, i.e., elevated pressure, reservoir temperature and anaerobic conditions.
The Slootdorp field has a complex structure with most reserves in Rotliegend sandstone, which is communicating with gas bearing Zechstein carbonates. The Rotliegend reservoir is bounded by a large fault, which might become seismogenic during depletion. A 3D geomechanical model was built, based on the faults and horizons in the geological model. Both the Rotliegend and Zechstein reservoirs were included in the model. The model was populated with geomechanical properties derived from logs, LOT's (leak off tests) and regional data on the stress field. Also, overburden properties from previous studies on nearby fields were used.
The pressure input was obtained from reservoir simulation. It is important to include the water leg pressure in the pressure input since the Rotliegend gas reservoir is in contact with an active aquifer. Pressure reduction drives the compaction of the reservoir, which induces stresses on the faults causing slippage. Since the water is quite incompressible, a large pressure reduction in the water leg may be caused temporarily by a rising gas water contact.
It turned out that slippage is not expected at the lowest gas pressure using a conservative estimate of the critical friction coefficient on the fault of 0.55. Sensitivity analysis on the most important input parameters was performed with a range that can be expected for such a field. The result was that the maximum critical stress ratio could range between 0.46 and 0.53 for the expected uncertainty of input parameters. The geomechanical modeling shows that an active aquifer has a dominant, mitigating effect on seismic risk, which can explain why many reservoirs show no seismicity in the Netherlands, although other effects could also play a role.
Lu, Cong (Southwest Petroleum University) | Li, Junfeng (Southwest Petroleum University) | Luo, Yang (SINOPEC Southwest Oil & Gas field Company) | Chen, Chi (Southwest Petroleum University) | Xiao, Yongjun (Sichuan Changning Gas Development Co. Ltd) | Liu, Wang (Sichuan Changning Gas Development Co. Ltd) | Lu, Hongguang (Huayou Group Company Oilfied Chemistry Company of Southwest) | Guo, Jianchun (Southwest Petroleum University)
Temporary plugging during fracturing operation has become an efficient method to create complex fracture network in tight reservoirs with natural fractures. Accurate prediction of network propagation process plays a critical role in the plugging and fracturing parameters optimization. In this paper, the interaction between one single hydraulic fracture within temporary plugging segment and multiple natural fractures was simulated using a complex fracture development model. A new opening criterion for NF penetrated by non-orthogonal HF already was implemented to identify the dominate propagation direction of HF under plugging condition. Fracture displacements and induced stress field were determined by the three dimensional displacement discontinuity method, and the Gauss-Jordan and Levenberg-Marquardt methods were combined to handle the coupling between rock mechanics and fluid flow numerically. Numerical results demonstrate that the opening and development of NF are mainly dominated by its approaching angle and relative location. For a certain NF crossed by HF within plugging segment, HF tends to propagate along the relative upper part when the approaching angle is less than 90°, otherwise the lower part will be easier to open. The farther interaction position is away from HF tip, the easier NF with approaching angle less than 30° or larger than 150° can be open, and the outcome will be opposite if the approaching angle is larger than 45° or less than 135°. Higher approaching angle and plugging strength is necessary for expanding the position scope of NF that can be opened around HF. Under the impact of plugging, fluid pressure in HF plummets at the beginning of NF opening and keeps decreasing until NF extending for a certain distance or encountering secondary NFs. Fluid pressure drop occurs mainly in the unturned NF, together with the width of unturned NF is significantly lower than that of turned NF and HF. Sensitivity analysis shows that the main factors, such as geometry, aperture profile, and fluid pressure distribution, affecting the network progress under temporary plugging condition are the horizontal differential stress, NF position, approaching angle, plugging time, and plugging segment length. The simulation results provide critical insight into complex fracture propagation progress under temporary plugging condition, which should serve as guidelines for welling choosing and plugging optimization in temporary plugging fracturing.
Transocean said will install automated drilling systems on four of its harsh-environment rigs on long-term contracts with Equinor. An additional rig will be outfitted with the automation technology before it begins work offshore Norway later this year. The five semisubmersibles will use a package of technologies developed by Sekal, NOV, and MHWirth, which Transocean says will deliver higher rates of penetration, better bottomhole pressure control, and gas kick detection. The news marks the second such announcement in as many months. In January, Seadrill and German exploration company Wintershall shared plans to use automated drilling systems on a newbuild rig contracted for a North Sea drilling campaign.
Ahmed Elfeel, Mohamed (Schlumberger) | Tonkin, Trevor (Schlumberger) | Watanabe, Shingo (Schlumberger) | Abbas, Hicham (Schlumberger) | Bratvedt, Frode (Schlumberger) | Goh, Gordon (Schlumberger) | Gottumukkala, Varma (Schlumberger) | Giddins, Marie Ann (Schlumberger)
Traditional reservoir management relies on irregular information gathering operations such as surface sampling and production logging followed by one or several treatment operations. The availability of both diagnosis and the prescribed remedial operations can cause severe delays in the reservoir management cycle, increasing unplanned down-time and impacting cash flow. These effects can be exacerbated in remote and offshore fields where well intervention is time-intensive.
A new, innovative, all-electric, flow control valve (FCV) is now a reality for smart completions. This can support any well penetration scenario including multiple zones per lateral in maximum reservoir contact wells and multi-trip completion in extended reach wells. Each zone is equipped with a permanent intelligent flow control valve, allowing real-time reservoir management and providing high-resolution reservoir control. Valve actuation is semi-instantaneous and field data has shown that the frequency of updating such valves is at least 50 times compared to conventional valves, enabling near continuous closed-loop reservoir management. However, such a high frequency optimization demands computational efficiency as it challenges existing optimization applications, particularly when multiple realizations are considered to account for reservoir uncertainty.
In this paper, we present a framework to support field-wide implementation of smart FCVs and hence maintaining a fast closed-loop reservoir management. The framework consists of history matching using Ensemble Kalman Filters (EnKF) where smart FCV data is assimilated to condition a suite of representative reservoir models at a relatively high frequency. Thereafter, a reactive optimizer utilizing a non-linear programming method is applied with the objectives of maximizing instantaneous revenue by determining the optimal positions of the downhole valves under user defined rate, pressure drop, drawdown and setting constraints. This optimization offers production control planning suggestions with the intent of immediate to short-term gain in oil production based upon the downhole measurement and the performance of the near wellbore model. At the same time, a proactive optimizer can be used to determine valve-control settings for longer term objectives such as delaying water/gas breakthrough. The objective of this optimization is equalization of the water/gas front arrival times based upon generation of streamlines and time-of-flight (TOF) analysis. Both modes of optimization are performed efficiently such that a single optimization run is sufficient per geological realization. We use the OLYMPUS reference model, a water flooding case, to demonstrate the workflow. The reactive optimization shows an increase of 25% in the net present value through minimizing water production and increasing injection efficiency, while proactive optimization delays water breakthrough time by 2-4 years. The paper showcases the effectiveness of complementary workflows where high frequency reactive and proactive optimizations support a near continuous closed-loop reservoir management.
Polymer flooding is a mature Enhanced Oil Recovery process which is used worldwide in many large- scale field expansions. Encouraged by these positive results, operators are still looking at applying the process in new fields even in the context of low oil prices and are evaluating its feasibility in more challenging reservoir conditions: high salinity, high hardness and high temperature. Several solutions have been proposed to overcome the limitations of the conventional hydrolyzed polyacrylamide (HPAM) in these types of challenging environments: biopolymers such as xanthan or scleroglucan, associative polymers, or co- or ter-polymers combining acrylamide with monomers such as ATBS or NVP. Each of these solutions has its advantages and disadvantages, which are not always clear for practicing engineers. Moreover, it is always interesting to study past field experience to confront theory with practice. This is what this paper proposes to do.
The paper will first review the limits of conventional HPAM and other polymers that have been proposed for more challenging reservoir conditions. But more than that, it will focus on the field experience with each of these products to establish some practical guidelines for the selection of polymers depending on the reservoir and fluid characteristics.
One first result of this review is that the limits of conventional HPAM may not be as low as usually expected. Biopolymers appear very sensitive to biodegradation and their success in the field has been limited. Associative polymers appear better suited to near-wellbore conformance control than to displacement processes and some of the new co and ter-polymers are currently being field tested with some measure of success. It appears that the main challenge lies with high temperature rather than high salinity; some field projects are currently ongoing in high salinity (200 g/L) and hardness.
The paper will help set the current limits for polymer flooding in terms of temperature, salinity and hardness based on laboratory work and field experience. This will prove a useful guide for practicing engineers looking to pilot polymer injection in challenging reservoir conditions.
Um, Evan Schankee (Earth and Environmental Sciences, Lawrence Berkeley National Laboratory) | Kim, Jihoon (Harold Vance Department of Petroleum Engineering, Texas A&M University) | Wilt, Michael (Earth and Environmental Sciences, Lawrence Berkeley National Laboratory) | Commer, Michael (Earth and Environmental Sciences, Lawrence Berkeley National Laboratory) | Kim, Seung-Sep (Geology and Earth Environmental Sciences, Chungnam National University)
We examine the detection and imaging sensitivity of surface electric field measurements over a 3D hydraulically active fracture zone (HAFZ) at depth when one end point of a surface electric dipole source is directly connected to a wellhead. This configuration is often called the top-casing electric source method. The sensitivity also depends on conductivity structures around the well because they control a leak-off of electrical currents from the steel-cased well. Our inversion experiments show that the method can delineate a localized HAFZ in a shallow to intermediate depth (e.g. ≤2 km) and can also detect changes in its width and height. The inversion results are improved when a volume of the subsurface imaging domain is reasonably constrained from geomechanical perspectives. The primary advantage of the method is the fact that the method has both source and receivers on the surface and thus, does not require well occupancy and interruption to the normal operation of the wells. Accordingly, it has potential to serve as a cost-effective tool for monitoring hydraulic fractures.
Presentation Date: Tuesday, October 16, 2018
Start Time: 1:50:00 PM
Location: 213A (Anaheim Convention Center)
Presentation Type: Oral
That is, how much fluid can be injected or extracted from the reservoir without triggering the mechanical failure of the reservoir and surrounding rocks. In an enhanced geothermal system, such as Horstberg in North German Basin (NGB), an induced hydraulic fracture is created by massive water injection to enhance the wellbore productivity and to increase the surface area of heat transfer. A safe operation in Horstberg geothermal system requires that induced hydraulic fracture and surrounding faults mechanically stay stable. Particularly, the further extension of the induced hydraulic fracture and reactivation of the preexisting faults should be prevented. On one hand, fault mechanics and stability of the faults are traditionally described by Mohr-Coulomb theory where a frictional instability along a preexisting fault surface may occur (Ellsworth, 2013) and on the other hand, the onset of fracture extension is described by fracture mechanics and a critical stress intensity factor which often regarded as a material property, fracture toughness (Anderson, 1991).
Nishi, Keisuke (Deep Ocean Resources Development Co., Ltd. (DORD)) | Koizumi, Akira (Deep Ocean Resources Development Co., Ltd. (DORD)) | Tsune, Akira (Deep Ocean Resources Development Co., Ltd. (DORD)) | Tanaka, Soichiro (Deep Ocean Resources Development Co., Ltd. (DORD))
In this study, we have considered the relation between topographic features and the distribution of polymetallic nodules based on their sizes and chemical composition in the Japanese License Area, Clarion-Clipperton Fracture Zone, Central Pacific. It has been observed that small nodules are distributed on rather steep slopes with relatively low Ni + Cu content (average 2.0%), whereas larger nodules are distributed on gentle slopes with higher Ni + Cu content (ave. 2.5%). These indicate that the size and chemical composition of nodules are controlled by topographic features and growth processes.
Polymetallic nodules (referred to as the “nodules”) are found on the deep-sea floor in all the oceans. It is known that the Clarion- Clipperton Fracture Zone (CCZ) has the highest density of the nodules in the world's ocean (e.g., Morgan, 2000). As the nodules generally contain an average of 28.4% Mn, 0.2% Co, 1.3% Ni, and 1.1% Cu (e.g., Hein, 2016), they are expected to become potential deep-sea mineral resources in the future. To date, the International Seabed Authority (ISA) has singed exploration contracts with 17 Contractors, including Deep Ocean Resources Development Co., Ltd. (DORD), which holds an exploration right for nodules in the Japanese License Area (JLA). JLA is approximately 75,000 km2, which is considerably broader than that of other deep-sea mineral resources. To explore the vast area, it is essential not only to use wide-ranging probes together with autonomous underwater vehicles (AUVs) (e.g., Okazaki and Tsune, 2013), vessel-mounted acoustic survey systems, and deep- towed instruments (e.g., Sharma, 2010; Kuhn et al., 2011; Tsune and Okazaki, 2014; Schoening et al., 2016) such as a side scan sonar and deep-sea camera but also to conduct sampling of the nodules and sediment. Data on the size, weight, coverage, and abundance of the nodules obtained from the sampling surveys by using box corers, large corers, dredging, and others have been utilized for estimating the resource as well as understanding the origin of the nodules. In addition, the distribution characteristics of nodules in relation to topography has been analyzed from different approaches such as acoustic investigation and seafloor observations (e.g., Usui et al., 1987; Nishimura, 1992; Sharma and Kodagali, 1993). However, despite the vast area, publicly available data is limited, which results in inadequate understanding of an overall distribution and origin of the nodules. Especially, it is commonly known that the nodules of various sizes exist, but the relationship between their size and chemical composition is not yet clearly understood.
We analyzed microseismic spatial and temporal distribution, magnitudes, b-values, and treatment data to interpret and explain the observed anomalies in microseismic events recorded during exploitation of shale gas reservoirs in the Horn River Basin of Canada. The b-value shows the relationship between the number of seismic events in a certain area and their magnitudes in a semilogarithmic scale. The b-value is important because small changes in b-value represent large changes in the predicted number of seismic events. In this study, b-value is considered as an indicator of the mechanism of observed microseismicity during hydraulic-fracturing treatments.
We estimated the directional diffusivity to define the microseismicity front curve for each stage of hydraulic fracturing. On the basis of our definition of an average front curve, we managed to separate most of the microseismic events that are related to natural-fracture activation from hydraulic-fracturing microseismic events. We analyzed b-values for microseismic events of each stage before and after separating fracture-activation microseismic events from original data, and created a map of b-values in the study area. This allowed us to approximately locate activated fractures mostly in the northeastern part of the study wellpad. The b-value map agrees with our assumption of activated-fracture locations and high ratio of seismic activities. The dominant direction of the suggested activated natural fractures agrees with the general trend of the Trout Lake fault zone located approximately 20 km west of the study area.
Suggested fracture direction also agrees with anomalous-events density, energy distribution, and treatment data. We are proposing intermediate b-values for calculation of the stimulated reservoir volume (SRV) in areas with both hydraulically fractured events and events related to natural-fracture-network activation in those instances in which it is not viable to separate events based on their origin.