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Abstract In this case study, we apply a novel fracture imaging and interpretation workflow to take a systematic look at hydraulic fractures captured during thorugh fracture coring at the Hydraulic Fracturing Test Site (HFTS) in Midland Basin. Digital fracture maps rendered using high resolution 3D laser scans are analyzed for fracture morphology and roughness. Analysis of hydraulic fracture faces show that the roughness varies systematically in clusters with average cluster separation of approximately 20' along the core. While isolated smooth hydraulic fractures are observed in the dataset, very rough fractures are found to be accompanied by proximal smoother fractures. Roughness distribution also helps understand the effect of stresses on fracture distribution. Locally, fracture roughness seems to vary with fracture orientations indicating possible inter-fracture stress effects. At the scale of stage lengths however, we see evidence of inter-stage stress effects. We also observe fracture morphology being strongly driven by rock properties and changes in lithology. Identified proppant distribution along the cored interval is also correlated with roughness variations and we observe strong positive correlation between proppant concentrations and fracture roughness at the local scale. Finally, based on the observed distribution of hydraulic fracture properties, we propose a conceptual spatio-temporal model of fracture propagation which can help explain the hydraulic fracture roughness distribution and ties in other observations as well.
Abstract Perforation-imaging studies have indicated highly variable results on effectively treating all perforation clusters within a given fracturing stage in horizontal well plug-and-perf applications, even when limited entry designs were used. A field test was executed to trial differing perforating designs and levels of perforation friction for identifying a preferred technique for evenly distributing treatment volume along the lateral. The test was implemented in a horizontal well in the Eagle Ford formation of south Texas. After treatment and plug drill-out operations were completed, a downhole camera was run to visualize perforation entry holes along the entire lateral section. Shaped perforating charges described as equal entry hole charges were used in all stages. The resulting images were analyzed to determine entry hole dimensions and erosion characteristics to determine if alternate perforating strategies provided improved results, as compared to the standard design of multi-phase perforating with 1200 psi of perforation friction. Test results indicate that orienting perforations in a straight line (zero-phase) along the high side of the wellbore significantly improved treatment distribution among perforation clusters. Oriented perforating achieved this benefit without needing to increase initial perforation friction beyond the area standard of 1200 psi. Another result from this project was development of a statistical process for evaluating perforation entry hole erosion data. Entry hole erosion datasets are complex and difficult to analyze. The statistical process presented in this paper demonstrates a clear way to compare the effectiveness of different perforation designs. This paper also covers the operational difficulties encountered during the project which added complexity to analyzing the results. Lastly, this paper offers suggestions for future modifications for oriented perforation designs to further improve limited entry effectiveness.
Abstract Well spacing and stimulation design are amongst the highest impact design variables which can dictate the economics of an unconventional development. The objective of this paper is to showcase a numerical simulation workflow, with emphasis on the hydraulic fracture simulation methodology, which optimizes well spacing and completion design simultaneously. The workflow is deployed using Cloud Computing functionality, a step-change over past simulation methods. Workflow showcased in this paper covers the whole cycle of 1) petrophysical and geomechanical modeling, 2) hydraulic fracture simulations and 3) reservoir simulation modeling, followed by 4) design optimization using advanced non-linear methods. The focus of this paper is to discuss the hydraulic fracture simulation methods which are an integral part of this workflow. The workflow is deployed on a dataset from a multi-well pad completed in late 2018 targeting two landing zones in the Vaca Muerta shale play. On calibrated petrophysical and geomechanical model, hydraulic fracture simulations are conducted to map the stimulated rock around the wellbores. Finely gridded base model is utilized to capture the property variation between layers to estimate fracture height. The 3d discrete fracture network (DFN) built for the acreage is utilized to pick the natural fracture characteristics of the layers intersected by the wellbores. The methodology highlights advances over the past modeling approaches by including the variation of discrete fracture network between layers. The hydraulic fracture model in conjunction with reservoir flow simulation is used for history matching the production data. On the history matched model, a design of experiments (DOE) simulation study is conducted to quantify the impact of a wide range of well spacing and stimulation design variables. These simulations are facilitated by the recent deployments of cloud computing. Cloud computing allows parallel running of hundreds of hydraulic fracturing and reservoir simulations, thereby allowing testing of many combinations of stimulation deigns and well spacing and reducing the effective run time from 3 months on a local machine to 1 week on the cloud. Output from the parallel simulations are fitted with a proxy model to finally select the well spacing and stimulation design variables that offer the minimum unit development cost i.e. capital cost-$ per EUR-bbl. The workflow illustrates that stimulation design and well spacing are interlinked to each other and need to be optimized simultaneously to maximize the economics of an unconventional asset. Using the workflow, the team identified development designs which increase EUR of a development area by 50-100% and reduce the unit development cost ($/bbl-EUR) by 10-30%.
Abstract In multi-stage plug-and-perf horizontal well completions, there are a multitude of moving parts and variables to consider when evaluating performance drivers. Properly identifying performance drivers allows an operator to focus their efforts to maximize the rate of return of resource development. Typically, well-to-well comparisons are made to help identify performance drivers, but in many cases the differences are not clear. Identifying these drivers may require a better understanding of performance variability along a single lateral. Data analytics can help to identify performance drivers using existing data from development activities. In the case study below, multiple diagnostics are utilized to identify performance drivers. A combination of completion diagnostics including oil and water tracers, stimulation data, reservoir data, 3D seismic, and borehole image logs were collected on a set of wells in the early appraisal phase of a field. Using oil tracers as the best indication of stage level performance along the laterals, data analytics is applied to uncover the relationships between the tracers and the numerous diagnostics. After smoothing was applied to the dataset, trends between oil tracer recovery, several independent variables and features seen in image logs and 3D seismic were identified. All the analyses pointed to decreasing tracer recovery, and likely decreased oil production, near faulted areas along each lateral. A random forest model showed a moderate prediction power, where the model's predicted tracer recovery on blind stages was able to explain 54% of the variance seen in the tracer response (r=0.54). This analysis suggests the identification of certain faulted areas along the wellbore could lead to ways of improving individual well economics by adjusting completion design in these areas.
Gopani, Paras Himmat (University of Calgary) | Singh, Navpreet (University of Calgary) | Sarma, Hemanta Kumar (University of Calgary) | Negi, Digambar S. (Oil and Natural Gas Corporation Limited) | Mattey, Padmaja S. (Oil and Natural Gas Corporation Limited)
Abstract As carbonate reservoirs are mostly oil-wet, the potential for the success of a waterflooding is lower. Therefore, a primary focus during waterflooding such reservoirs is on the ionic composition and salinity of injected brine which are able to impact the alteration of the rock wettability favorably by altering the surface charge towards a higher negative value or close to zero. The objective of this study is to employ zeta potentiometric studies comprising streaming potential and streaming current techniques to quantify the surface interactions and charges between the carbonate rock and fluid type as a function of the variations in its ionic state and rock saturation. Zeta potentiometric studies were conducted on carbonate rock samples to understand the behavior of different aqueous solutions by variation in the brine's salinity and ionic composition and the results were integrated with wettability studies. The concentrations of potential-determining ions (PDIs) such as SO4, Mg and Ca in the injected brines are deemed responsible for altering the wettability state of the carbonate rocks. Several diluted brines (25%, 10% and 1% diluted seawater) and smart brines have been investigated. Smart brines were prepared by spiking the concentration of major PDIs. All zeta potential measurements were conducted using a specially designed zeta potentiometer sample-holding clamp capable of using the whole core plugs rather than pulverized rock samples. A major advantage of using the whole core sample is that the same core can be used in subsequent coreflooding tests, thus making zeta potentiometric results more relevant and representative for a particular rock-fluid system used in the study. The classical streaming potential and streaming current techniques were used for zeta potential measurement. The Fairbrother-Mastin approach was used where the streaming potential is measured against different pressure differentials. Measurements were also carried out for brines with rock samples of different states: oil-saturated, water-saturated and rock samples cleaned with organic solvents to determine any likely variations in surface charge interactions. The results of our experiments imply that the value of zeta potential either increases or becomes more negative with increasing percentage of dilution (25%, 10%, and 1%). This can be attributed to electrical double-layer expansion which is primarily caused by reduced ionic strength. Furthermore, with measurements done on smart brines, zeta potential value was also found to be increased when different diluted brines are spiked with ionic concentration of PDIs such as sulfate. This could have been caused by surface ion alteration mechanism where PDIs get adsorbed on rock surface causing possible detachment of oil droplets. Both the phenomena are known mechanisms for altering wettability towards more water wetness in carbonate rocks and are discussed in detail.
Wang, Shihao (Colorado School of Mines) | Di, Yuan (Peking University) | Winterfeld, Philip H. (Colorado School of Mines) | Li, Jun (King Fahd University of Petroleum and Minerals) | Zhou, Xianmin (King Fahd University of Petroleum and Minerals) | Wu, Yu-Shu (Colorado School of Mines) | Yao, Bowen (Colorado School of Mines)
Summary In this paper, we aim to enhance our understanding of the multiphysical processes in carbon dioxide (CO2)-enhanced-oil-recovery (EOR) (CO2-EOR) operations using a modeling approach. We present the development of a comprehensive mathematical model for thermal/hydraulic/mechanical (THM) simulation of CO2-EOR processes. We adopt the integrated-finite-difference method to simulate coupled THM processes during CO2-EOR in conventional and unconventional reservoirs. In our method, the governing equations of the multiphysical THM processes are solved fully coupled on the same unstructured grid. To rigorously simulate the phase behavior of a three-phase, nonisothermal system, a three-phase flash-calculation module, dependent on the minimization of Gibbs energy, is implemented in the simulator. The simulator is thus applicable to both miscible and immiscible flooding simulations under isothermal and nonisothermal conditions. We have investigated the effect of cold-CO2 injection on injectivity as well as on phase behavior. We conclude that cold-CO2 injection is an effective way to increase injectivity in tight oil reservoirs and reduces overriding effect in high-water-bearing reservoirs. Using the developed general simulation framework, we have discovered and studied several intriguing multiphysical phenomena that cannot be captured by commonly used reservoir simulators, including the temperature-decreasing phenomenon near the production well and the permeability-enhancement effect induced by the thermal unloading process. These phenomena can be captured only by the fully coupled multiphysical model. The novelty of this paper lies in its integration of multiple physical simulation modules to form a general simulation framework to capture realistic flow and transport processes during CO2 flooding, and in revealing the behavior of cold-CO2 injection under THM effects.
Jin, Ge (Colorado School of Mines (Corresponding author) | Ugueto, Gustavo (email: firstname.lastname@example.org)) | Wojtaszek, Magdalena (Shell Exploration and Production Company) | Guzik, Artur (Shell International) | Jurick, Dana (Neubrex Co., Ltd.) | Kishida, Kinzo (Neubrex Energy Services)
Summary The characteristics of hydraulic fractures in the near-wellbore region contain critical information related to the production performance of unconventional wells. We demonstrate a novel application of a fiber-optic-based distributed strain sensing (DSS) technology to measure and characterize near-wellbore fractures and perforation cluster efficiency during production. Distributed fiber-optic-based strain measurements are made based on the frequency shift of the Rayleigh scatter spectrum, which is linearly dependent on strain and temperature changes of the sensing fiber. Strain changes along the wellbore are continuously measured during the shut-in and reopening operations of a well. After removing temperature effects, extensional strain changes can be observed at locations around the perforation cluster during a shut-in period. We interpret that the observed strain changes are caused by near-wellbore fracture aperture changes caused by pressure increases within the near-wellbore fracture network. The depth locations of the measured strain changes correlate well with distributed acoustic sensing (DAS) acoustic intensity measurements that were measured during the stimulation of the well. The shape and magnitude of the strain changes differ significantly between two completion designs in the same well. Different dependencies between strain and borehole pressure can be observed at most of the perforation clusters between the shut-in and reopening periods. We assess that this new type of distributed fiber-optic measurement method can significantly improve understanding of near-wellbore hydraulic fracture characteristics and the relationships between stimulation and production from unconventional oil and gas wells.
Abstract Natural gas is the noble fuel of 21st century. Consumption increased nearly 30% in last decade. Exploitation of conventional, unconventional, and contaminated gas resources are in focus to meet the demand. There are number of giant gas fields discovered worldwide and some of them with higher degree of contaminants viz. CO2, H2S and Hg. Additionally, they have operating challenges of high pressure and temperature. It becomes more complex when discovery is in offshore environment. This study presents the development and production, separation, transportation and identification & evaluation of storage sites and sequestration and MMV plan of a giant carbonate gas field in offshore Malaysia. Geological, Geophysical and petrophysical data used to describe the reservoir architecture, property distribution and spatial variation in more than 1000m thick gas bearing formation. Laboratory studies carried out to generate the rock and fluid representative SCAL (G-W), EOS and Supercritical CO2-brine relative permeability, geomechanics and geochemical data for recovery and storage estimates in simulation model and evaluating the post storage scenario. These data are critical in hydrocarbon gas prediction and firming up the number of development wells and in the simulation of CO2 storage depleted carbonate gas field. Important is to understand the mechanism in the target field for storage capacity, types of storage- structural and stratigraphic trapping, solubility trapping, residual trapping and mineral trapping. Study covers methodologies developed for minimization of hydrocarbon loss during contaminants separation and utilization of CO2 in usable products. Uncertainty and risk analysis have been carried out to have range of solution for production prediction and CO2 storage. Coupled Simulation studies predict the production plateau rate and 5 Tscf recovery separated contaminants profile and volume > one Tscf in order to have suitable geological structure for storage safely forever. Major uncertainties in the dynamic and coupled geomechanical-geochemical dynamic model has been captured and P90, P50, P10 forecast and storage rates and volumes have been calculated. Results includes advance methodologies of separation of hydrocarbon gas and CO2 like membrane and cryogenics for bulk separation of CO2 from raw gas and its transportation in liquid and supercritical form for storage. Study estimates components of sequestration mechanism, effect of heterogeneity on transport in porous media and height of stored CO2 in depleted reservoir and migration of plume vertically and horizontally. Generation of chemical product using separated CO2 for industrial use is highlighted.
Soltani, Amir (Beicip-Franlab) | Decroux, Benoit (Beicip-Franlab) | Negre, Andres (Beicip-Franlab) | Le Maux, Thierry (Beicip-Franlab) | Djarir, Maâmar (Sonatrach) | Selmi, Farouk (Sonatrach) | Lantoine, Martin (Beicip-Franlab)
Abstract EOR surfactants are usually formulated at the initial reservoir temperature. Is this a correct approach? Field data from three Single-Well Chemical Tracer pilots in North Africa are used to answer this question. The objectives are, first, to provide a realistic image of the temperature variations inside the water-flooded reservoir; second, to demonstrate the impact of such temperature variations on the surfactant performances; and last, to introduce a new methodology for estimating the target temperature window for surfactant formulations. During pre-SWCTT pilot tests, water injection, shut-in and back-production were performed. The bottom-hole temperature was monitored to evaluate the reservoir temperature changes (initially at 120°C) and to calibrate a thermal model. The thermal parameters were applied to the reservoir model to simulate 30 years of water injection (with its surface temperature varying between 20°C and 60°C) and to obtain a full picture of the temperature variations inside the reservoir. Multi-well surfactant injection was modelled assuming that the surfactant is only efficient within ±10°C around the design temperature. The impact of this assumption on the additional oil recovery was analyzed for several scenarios. The rock thermal transmissivity was found to be the key parameter for properly reproducing the observed data gathered in the North African pre-SWCTT tests. The measured temperature during the back-production phase demonstrated the accuracy of the thermal model parametrization. It proved that the heat exchange between the reservoir and the injected fluid is considerably less than what industry expects: the injected water temperature inside the reservoir remains far below the initial reservoir temperature even after 11 days of shut-in. When simulating various historical bottom-hole injection temperatures and pre-flush durations, the thermal model showed an average cooling radius of 275m, larger than the industry recommended well-spacing for the EOR 5-spot patterns. This was mainly due to the significant temperature difference between the historical injected water and the initial reservoir temperature. Several simulations were performed for 3 representative bottom-hole injection temperatures of 20°C, 40°C and 60°C, varying the surfactant design temperature range between the injection temperature and the initial reservoir temperature. The results showed that regardless of the injection temperature, the simulated additional oil recovery is highest when the design temperature range is close to the injection bottom-hole temperature. This is an important subject since in the EOR industry, the surfactants are usually formulated at the initial reservoir temperature and thus, the impact of the reservoir cooling on the surfactant efficiency is seldom considered. In a water flooded reservoir, the injected chemicals are unlikely to encounter the initial reservoir temperature. This results in a dramatic loss of surfactant performance especially when there is a considerable difference between the initial reservoir and the injected fluid temperatures.
Abstract One of the major brownfields in offshore India was producing for three decades from main carbonate reservoirs of the Eocene and Oligocene age. Average production of this brownfield is approximately 11,000 barrels of oil per day (BOPD). To maintain the declining reservoir pressure, the field has been under active water injection for more than two decades. However, being a complex carbonate reservoir with high textural heterogeneity, the water-front movement is not very well understood and monitored. To increase the oil production, the operator started drilling horizontal drain-holes from the platforms and has adopted a conventional perforated and blind tubing combination as a completion strategy. However, it was found that wells were performing poorly with very high water cut. An integrated and comprehensive petrophysical workflow was applied that used data analysis and the added value of advanced 3D acoustic data in combination with nuclear magnetic resonance (NMR) data to provide a rapid realistic solution to avoid such high watercut through optimizing the completion strategy. This led to a production gain in this offshore field, which was underperforming as per earlier predictions and expectations. Conventional well-log based qualitative evaluation for horizontal segmentation strategy was rejected in favor of an integrated approach for lateral reservoir facies delineation. Lateral petrophysical property characterization was carried out through quick integration of NMR pore-size driven facies analysis, advanced acoustic radial profiling, anisotropy, and Stoneley analysis. Permeability profiling along the horizontal drain-hole section using NMR and acoustics provided critical insight. Those were integrated to avoid potential high permeability conduits of thief zones for water breakthrough. A rock-quality index was derived to optimize the completion strategy soon after the logging, even preceding the rig-down of the acquisition runs and lowering of the completion. Zones with higher skin, deeper formation damage, and lower rock-mechanical properties were avoided for efficient swell-packer placements. The well started producing and continued production with only 10% water cut along with 450 barrels of oil compared to an average 90% watercut and 100 barrels of oil from the other wells of the same platform, which used the older nonoptimized completion strategy. Based on the promising result for the first well, the same workflow was used for two similar wells of other two different platforms inthe same field, which also resulted in similar production with enhanced oil production and reduced water cut. The study using the rapid integrated evaluation workflow established efficient zonal isolation of high permeability thief zones with accuracy for timely optimization of horizontal well segmentation, which assisted in pulling higher production in this brownfield by reducing unwanted water production.