|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Abstract Market-induced production shut-downs and restarts offer us an opportunity to gather step-rate and shut-in data for pressure transient analysis (PTA) and rate transient analysis (RTA). In this study, we present a unified transient analysis (UTA) to combine PTA and RTA in a single framework. In this new approach continuous production data, step-rate data, shut-in data and re-start data can be visualized and analyzed in a single superposition plot, which can be used to estimate both and infer formation pore pressure in a holistic manner by utilizing all available data. Most importantly, we show that traditional log-log and square root of time plots can lead to false interpretation of the termination of linear-flow or power-law behavior. Field cases are presented to demonstrate the superiority of the newly introduced superposition plot, along with discussion on the calibration of long-term bottom-hole pressure with short-term measurements.
Mondal, Somnath (Shell Exploration & Production Co.) | Zhang, Min (University of Texas at Austin) | Huckabee, Paul (Shell Exploration & Production Co.) | Ugueto, Gustavo (Shell Exploration & Production Co.) | Jones, Raymond (Shell Exploration & Production Co.) | Vitthal, Sanjay (Shell Exploration & Production Co.) | Nasse, David (Shell Exploration & Production Co.) | Sharma, Mukul (University of Texas at Austin)
Abstract This paper presents advancements in step-down-test (SDT) interpretation to better design perforation clusters. The methods provided here allow us to better estimate the pressure drop in perforations and near-wellbore tortuosity in hydraulic fracturing treatments. Data is presented from field tests from fracturing stages with different completion architectures across multiple basins including Permian Delaware, Vaca Muerta, Montney, and Utica. The sensitivity of near-wellbore pressure drops and perforation size on stimulation distribution effectiveness in plug-and-perf (PnP) treatments is modeled using a coupled hydraulic fracturing simulator. This advanced analysis of SDT data enables us to improve stimulation distribution effectiveness in multi-cluster or multiple entry completions. This analysis goes much further than the methodology presented in URTeC2019-1141 and additional examples are presented to illustrate its advantages. In a typical SDT, the injection flowrate is reduced in four or five abrupt decrements or "steps", each with a duration long enough for the rate and pressure to stabilize. The pressure-rate response is used to estimate the magnitude of perforation efficiency and near-wellbore tortuosity. In this paper, two SDTs with clean fluids were conducted in each stage - one before and another after proppant slurry was injected. SDTs were conducted in cemented single-point entry (cSPE) sleeves, which present a unique opportunity to measure only near-wellbore tortuosity using bottom-hole pressure gauge at sleeve depth, negligible perforation pressure drops, and less uncertainty in interpretation. SDTs were conducted in PnP stages in multiple unconventional basins. The results from one set of PnP stages with optic fiber distributed sensing were modeled with a hydraulic fracturing simulator that combines wellbore proppant transport, perforation size growth, near-wellbore pressure drop, and hydraulic fracture propagation. Past SDT analysis assumed that the pressure drop due to near-wellbore tortuosity is proportional to the flow rate raised to an exponent, β = 0.5, which typically overestimates perforation friction from SDTs. Theoretical derivations show that β is related to the geometry and flow type in the near-wellbore region. Results show that initial β (before proppant slurry) is typically around 0.5, but the final value of β (after proppant slurry) is approximately 1, likely due to the erosion of near-wellbore tortuosity by the proppant slurry. The new methodology incorporates the increase in β due proppant slurry erosion. Hydraulic fracturing modeling, calibrated with optic fiber data, demonstrates that the stimulation distribution effectiveness must consider the interdependence of proppant segregation in the wellbore, perforation erosion, and near-wellbore tortuosity. An improved methodology is presented to quantify the magnitude of perforation and near-wellbore tortuosity related pressure drops before and after pumping of proppant slurry in typical PnP hydraulic fracture stimulations. The workflow presented here shows how the uncertainties in the magnitude of near-wellbore complexity and perforation size, along with uncertainties in hydraulic fracture propagation parameters, can be incorporated in perforation cluster design.
Summary Mitigating the negative impact of fracture hits on production from parent and child wells is challenging. This work shows the impact of parent‐well depletion and repressurization on child‐well fracture propagation and parent‐well productivity. The goal of this study is to develop a method to better manage production/injection in the parent well so that the performance of the child well can be improved by minimizing fracture interference and fracture hits. A fully integrated equation‐of‐state compositional hydraulic fracturing and reservoir simulator has been developed to seamlessly model fluid production/injection (water or gas) in the parent well and model propagation of multiple fractures from the child well. The effects of drawdown rate and production time is presented for a typical shale play for three different fluid types: black oil, volatile oil, and dry gas. The results show that different reservoir fluids and drawdown strategies for the parent wells result in different stress distributions in the depleted zone, and this affects fracture propagation in the child well. Different strategies were studied to repressurize the parent well by varying the injected fluids (gas vs. water), the volumes of the preload fluid, and so on. It was found that fracture hits can be avoided if the fluid injection strategy is designed appropriately. In some poorly designed preloading strategies, fracture hits are still observed. Last, the impact of preloading on the parent‐well productivity was analyzed. When water was used for preloading, water blocking was observed in the reservoir, and it caused damage to the parent well. However, when gas was injected for preloading, the oil recovery from the parent well was observed to increase. Such simulations of parent–child well interactions provide much‐needed quantification to predict and mitigate the damage caused by depletion, fracture interference, and fracture hits.
Abstract The pressure decline data after the end of a hydraulic fracture stage is sometimes monitored for an extended period of time (30 minutes to hours). However, this data is not analyzed and often ignored or underappreciated due to a lack of suitable models for closure of propped fractures. In this study, we present a new approach to model and analyze pressure decline data that is available at the end of each plug and perf stage in horizontal wells. The new model, interpretation method and specialized plots presented in this study allow us to quantify closure stress, average pore pressure inside the stimulated reservoir volume (SRV) and normalized fracture stiffness/compliance evolution along the entire horizontal wellbore without additional data acquisition costs. Analysis of field stage-by-stage pressure decline data shows that the interpreted results are consistent with the analysis of DFIT data from an offset well for the same formation. We found that the early-time stage-by-stage pressure decline trend is controlled by progressive hydraulic fracture closure on the proppant pack, while late-time pressure decline reflects linear flow. Thus, the pressure decline rate alone is not a reliable indicator of the productivity or stimulation efficiency of a certain stage. When DFIT data is not available, pressure decline analysis of a main hydraulic fracturing stage can be used even if it can be monitored for a relatively short period of time (1 hour). Most important of all, we show that the slope of pressure derivative on a log-log plot and the normalized fracture stiffness plot can be used to infer the uniformity of proppant distribution.
Ozowe, Williams (The University of Texas at Austin) | Quintanilla, Zach (The University of Texas at Austin) | Russell, Rod (The University of Texas at Austin) | Sharma, Mukul (The University of Texas at Austin)
Despite recent technological advances in horizontal drilling and hydraulic fracturing, primary production from unconventional oil reservoirs is usually less than 10 percent of the original oil in place. This low recovery has made it essential for operators to test methods that aim to improve recovery efficiency and recover incremental oil from existing wells. One of such methods is the use of solvents for improved recovery in shale oil reservoirs via cyclic gas injection also referred to as a "huff-n-puff" process. Previous laboratory studies have demonstrated promising results on unpreserved shale core plugs using CO2, N2 and C1 as solvents, however, none have shown recovery results using ethane or higher molecular weight gases for cyclic gas injection.
This paper presents improved oil recovery results from cyclic gas injection experiments using C2 and n-C5 in comparison to N2 on unpreserved Eagle Ford crushed samples and core plugs with n-C12 as the oil phase. Core plugs and crushed preserved shale samples were vacuum dried and then re-saturated with n-C12 at 6000 psi for 48 hours, then huff-n-puff experiments were conducted using n-C5, C2 and N2. Recovery factors obtained using n-C5 at injection pressures of 2000 psi and 5000 psi showed that oil recovery increased with an increase in surface area to volume ratio. For the same surface area to volume ratio, oil recovery is higher at higher injection pressures. A comparison of recovery factors between C2 and n-C5 show that C2 was more effective than n-C5 because it showed higher recovery factors at 2000 psi and 5000 psi injection pressure. NMR T2 distributions also showed that C2 was able to recover more oil from the small and intermediate pore sizes without leaving behind any residual fluid in the small pores unlike n-C5. The higher recovery factors obtained for C2 are a result of its lower viscosity and because it is able to expel more oil out of the shale pore space as it flashes to gas upon depressurization compared to n-C5. Comparing N2 recovery results to both C2 and n-C5 at 5000 psi injection pressure demonstrated that N2 yielded the lowest recovery factors because it is essentially immiscible with the oil. These experimental results can be used as the basis for scaling up to field scale huff-n-puff gas injection pilots.
Seth, Puneet (The University of Texas at Austin) | Elliott, Brendan (Devon Energy Production Co. LP) | Ingle, Trevor (Devon Energy Production Co. LP) | Kumar, Ashish (The University of Texas at Austin) | Zheng, Shuang (The University of Texas at Austin) | Sharma, Mukul (The University of Texas at Austin)
In recent years, hydraulic fracturing design has evolved significantly. Fluid volumes injected in a lateral have more than doubled to ~ 250,000 bbl/well (
We analyze the pressure response in offset parent wells in the Permian Basin during treatment of a nearby well. Fracture arrival times (time taken for the child well fractures to intersect with a nearby parent well) are investigated for multiple stages during child well stimulation. This information from field data is coupled with fracture modeling simulations to evaluate if a frac-job is over-stimulated. Stages that suggest over-stimulation are systematically analyzed and dynamic plots are presented, that compare the capital efficiency at different times during a frac job.
Optimal completion designs that achieve uniform distribution of injected fluid volumes into multiple clusters are key to successful fracturing jobs. Simulations as well as field data show that if a large job volume is pumped with a sub-optimal completion design, fracture arrival at the offset well is early, leading to over-stimulation and wasted capital. In such a scenario, dominant clusters that take most of the injected fluid can intersect nearby offset well early in the treatment, while significantly bypassing undepleted reservoir rock along the lateral (that should ideally be drained) due to low cluster efficiency. This results in a frac job with poor capital efficiency and a well with lower productivity (due to interference with offset well). We show that early fracture arrival times are indicative of fewer clusters propagating fractures with very non-uniform fluid distribution (low cluster efficiency), whereas late arrival times indicate more uniform fluid distribution in the clusters with high cluster efficiency.
We introduce a novel technique that analyzes field offset well pressure data and fracture arrival times at the offset well to diagnose stimulation efficiency and prevent over-stimulation. Our method provides operators with a relatively inexpensive way to improve capital efficiency during a frac-job.
Lab experiments and numerical modeling have indicated that gas injection for IOR in tight oil reservoirs is technically feasible. Several operators have conducted pilots in the Eagleford and Bakken shales for a huff-n-puff IOR strategy with mixed results. Our objective in this work is to study the impact of (a) geomechanical effects during injection and fracture closure during production, (b) injection rate effect during huff-n-puff processes, (c) timing effect in huff-n-puff process, (d) phase behavior effects for huff-n-puff oil recovery, and (e) impact of soak time on oil recovery.
We developed and utilized a fully coupled geomechanical compositional fracturing/reservoir simulator for gas injection in tight oil reservoirs. The model calculates stress changes due to both poroelastic (pressure changes) and mechanical (fracture opening and closing) effects. Permeability hysteresis during loading/unloading cycles is also considered. The simulation procedure involves the following steps: (a) The well is produced for a period of time (b) Gas is injected into the well and this is simulated by specifying the injection rate and gas composition (c) The well is produced again after some soaking period, and the results are checked for any improvement in the oil recovery.
Based on our simulation studies, we observed several important trends. The degradation of permeability over multiple loading/unloading cycles due to hysteresis together with the poro-elastic effect severely impacts the oil recovery in later cycles. It was found that incremental oil recovery decreases after several huff-n-puff cycles. It was found that if higher gas injection rate gives higher oil recovery, but the oil recovery does not increase linearly with the injection rate. Phase behavior is found to be a key factor in the oil recovery and rich gas injection gives the best results. The impact of timing to initiate the huff-n-puff IOR was also studied. The soak time increases the ultimate oil recovery, but its impact is not significant in the study.
Our simulation results provide operators with significant new insights on the design of huff-n-puff IOR. It is shown that fracture widening and closure during huff-n-puff cycles have a significant impact on oil recovery. The novelty of the work is the development and use of compositional geomechanical model for IOR performance evaluation.
In this paper, we present an integrated equation-of-state based compositional hydraulic fracturing and reservoir simulator. The goal of this research is to develop a general simulator that can simulate the lifecycle of wells, which includes hydraulic fracturing treatment using water-based or energized fracturing fluid, post-frac shut-in and flowback with fracture closure and proppant settling, primary production with proppant embedment and fluid reinjection in a multiple well pad.
This simulator fully couples the reservoir, fracture, and wellbore domains with multiple physics in each domain. The rock deformation, porous flow and temperature change in the reservoir domain, fluid and proppant transport in the fracture domain, and wellbore slurry flow and fluid/proppant distribution among clusters are fully coupled together and solved fully implicitly using the Newton-Raphson method. The phase behavior of hydrocarbon phases is modeled using Peng-Robinson Equation-of-state. The fracture propagation is modeled by mesh topology change (dynamic remeshing and local refinement) and the propagation direction is evaluated using the stress intensity factors. This simulator has been fully parallelized using MPI. We show two applications of this simulator for lifecycle analysis in US unconventional oil reservoirs on frac-hits and CO2 fracturing.
In the first field application, we simulate a multi-well fracture diagnostics. We used the parent well to monitor the child well fracture growth. Child well fracture growth is correctly interpreted using the monitoring data. In the second field application, we perform lifecycle analysis of hydraulic fracturing treatment using hybrid CO2-slick water-crosslinked gel fracturing fluids and 100/30-50 mesh proppants and the following production phase from a well in the Bakken formation. We successfully match the complex surface treating pressure data from the field. We also successfully matched the cumulative production of oil, gas and water and explained the long-term CO2 flowback phenomenon in the field.
The novelty of this simulator comes from its unique modeling capability in the well lifecycle analysis. Fully coupled reservoir-fracture-wellbore framework allows accurate modeling of hydraulic fracture propagation in multiple well pads using multiple fracturing fluids and proppants, fracture closure during shut-in, primary production, refracturing, and pre-loading for parent well protection, and huff-n-puff improved oil recovery, all in one simulation. This simulator can be used as a reliable and efficient tool by operators in well lifecycle analysis.
The primary objective of this work was to investigate the results and the possible mechanisms of oil recovery in a huff-n-puff style improved oil recovery (IOR) field pilot using nanoparticle assisted CO2 injection. A secondary objective was to study the sensitivity of the process to injection volume of nanoparticles and gas, the type of injected gas, soaking period, and the timing of IOR to maximize net present value. An Eagle Ford shale well was produced for 526 days before 167-barrels of nanoparticle treatment and 160-tons of CO2 were injected in 11 cycles into the well, shut-in for 5 days and then put back on production. A simulation study was conducted using a fully coupled geomechanical compositional fracturing and reservoir simulator using data from the pilot well. The primary production was history matched for the fractured horizontal well and the huff-n-puff process with nanoparticle and CO2 injection was simulated followed by a shut-in period. The simulated production after shut-in and the incremental oil recovery was compared with field measured data. The pilot test results clearly show that there is a significant oil rate increase after the nanoparticle and CO2 are injected. Lab results show that nanoparticles can lower the interfacial tension between the water and oil and alter the rock wettability to a preferential water-wet state, which is beneficial for oil production. The simulation studies show that CO2 injection alone results in smaller improved oil recovery and predicts a smaller oil recovery than in the field. This suggests that both the nanoparticles and gas play an important role in increasing the relative permeability to oil and improving oil recovery. Results from the sensitivity study show that larger injection volumes of nanoparticles and gas result in higher oil recovery. Among different injection gases simulated, in this oily window of the Eagle Ford shale, ethane gives the highest oil recovery followed by CO2, methane, and nitrogen. A longer soaking period after the injection also helps to increase oil recovery. It is also shown that it may be better to perform IOR at an earlier stage of primary production to maximize the cumulative oil recovery. Our field and simulation results provide operators with significant new insights into the design of an IOR process that uses nanoparticles with CO2 injection. The integration of field pilot test data with realistic compositional geomechanical reservoir simulation for the first time provides a quantitative estimate of the improvement in oil recovery and insights into the possible mechanisms of oil recovery.
Hwang, Jongsoo (The University of Texas Austin) | Zheng, Shuang (The University of Texas Austin) | Sharma, Mukul (The University of Texas Austin) | Chiotoroiu, Maria-Magdalena (OMV Exploration & Production GmbH) | Clemens, Torsten (OMV Exploration & Production GmbH)
Reservoir cooling by water or waste-water injection can significantly alter the reservoir stress. The out- of-zone fracture growth is substantially affected by this poro-thermo-elastic stress changes occurring in heterogeneous rock layers. No previous study, however, systematically investgated the influence of heat conduction and convection on the associated stress alteration and fracture height growth during the long- term water injection in multiple layers. Without understanding this coupled effect, which occurs over a long-term fracture propagation, it is difficult to capture the conditions for the fractures to breach into the bounding shale layers.
In this paper, we present that the thermal conduction between the injection sand and bounding shale is crucial in predicting the fracture containment during water injection. We developed a fully coupled compositional reservoir/fracturing simulator that solves poro-thermo-elasticity. We used it to simulate 3- dimensional fracture propagation induced by cold water injection and, at the same time, calculate the stress field influenced by the thermo-poro-elastic effect in heterogeneous reservoir layers. Effective stress in the bounding layer is dynamically updated to capture the poro-thermo-elastic effect and associated fracture height growth. We first validate our model with existing analytical solutions and studied a field case. We identify the effects of fluid properties, rock properties, and injection temperature on stress changes and the fracture containment for the first time.