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Abstract The analyses of parent-child well performance is a complex problem depending on the interplay between timing, completion design, formation properties, direct frac-hits and well spacing. Assessing the impact of well spacing on parent or child well performance is therefore challenging. A naïve approach that is purely observational does not control for completion design or formation properties and can compromise well spacing decisions and economics and perhaps, lead to non-intuitive results. By using concepts from causal inference in randomized clinical trials, we quantify the impact of well spacing decisions on parent and child well performance. The fundamental concept behind causal inference is that causality facilitates prediction; but being able to predict does not imply causality because of association between the variables. In this study, we work with a large dataset of over 3000 wells in a large oil-bearing province in Texas. The dataset includes several covariates such as completion design (proppant/fluid volumes, frac-stages, lateral length, cluster spacing, clusters/stage and others) and formation properties (mechanical and petrophysical properties) as well as downhole location. We evaluate the impact of well spacing on 6-month and 1-year cumulative oil in four groups associated with different ranges of parent-child spacing. By assessing the statistical balance between the covariates for both parent and child well groups (controlling for completion and formation properties), we estimate the causal impact of well spacing on parent and child well performance. We compare our analyses with the routine naïve approach that gives non-intuitive results. In each of the four groups associated with different ranges of parent-child well spacing, the causal workflow quantifies the production loss associated with the parent and child well. This degradation in performance is seen to decrease with increasing well spacing and we provide an optimal well spacing value for this specific multi-bench unconventional play that has been validated in the field. The naïve analyses based on simply assessing association or correlation, on the contrary, shows increasing child well degradation for increasing well spacing, which is simply not supported by the data. The routinely applied correlative analyses between the outcome (cumulative oil) and predictors (well spacing) fails simply because it does not control for variations in completion design over the years, nor does it account for variations in the formation properties. To our knowledge, there is no other paper in petroleum engineering literature that speaks of causal inference. This is a fundamental precept in medicine to assess drug efficacy by controlling for age, sex, habits and other covariates. The same workflow can easily be generalized to assess well spacing decisions and parent-child well performance across multi-generational completion designs and spatially variant formation properties.
This includes identifying the acid optimum injection rate and volume, which leads to the minimum amount of acid required to achieve efficient wormhole propagation (Wang et al. 1993). Many factors influence the optimum acid-injection conditions (Hoefner and Fogler 1989; Wang 1993; Mostofizadeh and Economides 1994; Fredd and Fogler 1998, 1999; Shukla et al. 2006; Qiu et al. 2013; Xue et al. 2019). Previous laboratory studies have suggested that permeability, saturation, heterogeneity, core dimensions, temperature, and pressure can significantly affect the propagation of the wormholes and the optimum injection-rate value. We cover the range and conclusions from these studies and highlight the limitations, gaps, and inconsistencies in the results. Shukla et al. (2006) classified saturation conditions associated with matrix acidizing into four cases. The first case is when the acid job is performed after well completion, in which the saturation condition is either an irreducible water or a residual oil saturation, depending on whether the drilling mud used is oil-or water-based, respectively.
Su, Xin (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum (Beijing) and The University of Oklahoma (Corresponding author) | Moghanloo, Rouzbeh G. (email: Xin.Sufirstname.lastname@example.org)) | Qi, Minhui (The University of Oklahoma) | Yue, Xiang-an (The University of Oklahoma and China University of Petroleum (East China))
Summary Formation damage mechanisms in general lower the quality of the near wellbore, often manifested in the form of permeability reduction, and thus reducing the productivity of production wells and injectivity of injection wells. Asphaltene deposition, as one of the important causes, can trigger serious formation damage issues and significantly restrict the production capacity of oil wells. Several mechanisms acting simultaneously contribute to the complexity associated with prediction of permeability impairment owing to asphaltene deposition; thus, integration of modeling efforts for asphaltene aggregation and deposition mechanisms seems inevitable for improved predictability. In this work, an integrated simulation approach is proposed to predict permeability impairment in porous medium. The proposed approach is novel because it integrates various mathematical models to study permeability impairment considering porosity reduction, particle aggregation, and pore connectivity loss caused by asphaltene deposition. To improve the accuracy of simulation results, porous media is considered as a bundle (different size) of capillary tubes with dynamic interconnectivity. The total volume change of interconnected tubes will directly represent permeability reduction realized in porous media. The prediction of asphaltene deposition in porous media is improved in this paper via integration of the particle aggregation model into calculation. The simulation results were verified by comparing with existing experimental data sets. After that, a sensitivity analysis was performed to study parameters that affect permeability impairment. The simulation results show that our permeability impairment model—considering asphaltene deposition, aggregation, and pore connectivity loss—can accurately reproduce the experimental results with fewer fitting or empirical parameters needed. The sensitivity analysis shows that longer aggregation time, higher flow velocity, and bigger precipitation concentration will lead to a faster permeability reduction. The findings of this study can help provide better understanding of the permeability impairment caused by asphaltene deposition and pore blockage, which provides useful insights for prediction of production performance of oil wells.
Summary Shear slip of pre-existing fractures can play a crucial role in hydraulic stimulation to enable production from unconventional shale reservoirs. Evidence of the phenomenon is found in microseismic/seismic events induced during stimulation by hydraulic fracturing. However, induced seismicity and permeability evolution in response to fracture shear slip by injection have not been extensively studied in laboratory tests under relevant conditions. In this work, a cylindrical Eagle Ford Shale sample having a single fracture (tensile fracture) was used to perform a laboratory injection test with concurrent acoustic emission (AE) monitoring. In the test, shear slip was induced on the fracture at near critical stress state by injecting pressurized brine water [7% potassium chloride (KCl)]. Sample deformation (stress, displacement), fluid flow (injection pressure, flow rate), and AE signals (hits, events) were all recorded. The data were then used to characterize the fully coupled seismo-hydromechanical response of the shale fracture during shearing. Results show that the induced AE/microseismic events correlate well with the fracture slip and the permeability evolution. Most of the recorded AE hits and events were detected during the seismic-slip interval corresponding to a rapid fracture slip and a large stress drop. As a result of dilatant shear slip, a remarkable enhancement of fracture permeability was achieved. Before this seismic interval, an aseismic-slip interval was evident during the tests, where the fracture slip, associated stress relaxation, and permeability increase were limited. The test results and analyses demonstrate the role of shear slip in permeability enhancement and induced seismicity by hydraulic stimulation for unconventional shale reservoirs. Introduction Shear slip of pre-existing fractures has long been recognized as a major permeability creation and microseismicity mechanism of reservoir stimulation (e.g., Pine and Batchelor 1984; Mayerhofer et al. 1997; Rutledge et al. 2004; Zoback et al. 2012).
Khan, Sikandar (The University of Oklahoma) | Karami, Hamidreza (The University of Oklahoma) | Wang, Chengbao (Baker Hughes) | Joshi, Mahendra (Baker Hughes) | Reeves, Brian (Baker Hughes) | Van Dam, Jeremy (Baker Hughes) | Johnson, Curtis (Baker Hughes)
Improvements on existing wells' potential are crucial towards ensuring an economically viable project. Among various artificial lift techniques, gas lift is considered as one of the most efficient when associated gas capacity is available, and well production parameters are favorable. Also, jet pumps are specifically favorable for horizontal wells due to the relative ease in downhole installation. This paper combines these two techniques to introduce and evaluate an innovative hybrid method. It provides optimum operating windows for its design and application.
This study aims to introduce and benchmark a newly proposed hybrid lift techniques for horizontal wells. Some features of this method are: 1) The operating Gas Lift Valve (GLV) is installed at the bottom of vertical. 2) The jet pump is installed below the GLV. 3) The power fluid and gas are injected through the casing-tubing annulus. 4) The pressure of gas, provided by the compressor, is used to push the power fluid through the jet pump nozzle and into the tubing. An analytical model is applied to simulate this hybrid lift technique through nodal analysis, combining models for reservoir inflow, flow through jet pump, and two-phase flow in wellbore.
A sensitivity study is conducted to understand the effects of depth, API gravity, water cut, reservoir pressure, gas-liquid ratio (or gas injection rate), nozzle pressure, and nozzle and throat area ratio (R ratio) on the proposed hybrid lift's performance. A hybrid lift operating window is defined as the conditions that result in higher production rates than gas lift alone. The largest operating window is present for shallower wells with larger tubing diameters. The R ratio effects are variable throughout the cases and an optimal R ratio design is needed for each specific case. The required optimal GLR is observed to be always lower for the hybrid lift system compared to gas lift, making it relatively easier and cheaper to achieve. Overall, the operating window for application of hybrid lift is: 1) larger tubing size, 2) higher water cuts, 3) shallower wells, 4) lower required GLR's, 5) heavier oils, 6) higher nozzle pressures, 7) depleted reservoir pressures, 8) higher R ratios (if the well can handle the friction). Additional economic considerations are necessary to better evaluate this technique and determine its optimum operating window.
This innovative hybrid gas lift technique can be widely applied towards increasing well's performance, life, and economic viability. It shows its true merit in seemingly less promising and difficult cases with higher water cuts and lower reservoir pressures by increasing benefit throughout the life of the well.
Sharma, Ashutosh (The University of Oklahoma) | Iradukunda, Platin (The University of Oklahoma) | Karami, Hamidreza (The University of Oklahoma) | McCoy, J. N. (Echometer company) | Podio, A. L. (Echometer company) | Teodoriu, Catalin (The University of Oklahoma)
With the ever-increasing trend of oil production from lower pressure wells, application of artificial lift techniques is becoming inevitable. Beam pumps and electrical submersible pumps are two of the most common artificial lift methods for low and high oil production rates. But these techniques are susceptible to high gas-oil ratios, particularly at lower wellbore pressures causing gas break-out and possible gas lock. Various types of downhole separators have been recently designed upstream of the pump to resolve this issue and improve the pump efficiency. The objective of this study is to construct a state-of-art experimental facility and simulate the flow in an oil well with varying gas-oil ratios. The facility is then used to evaluate the performance of a centrifugal downhole separator.
The experimental multiphase flow setup is designed, fabricated, and constructed in an efficient and automated way to simulate a typical horizontal wellbore. The well trajectory includes a 31-ft horizontal section, inclinable to ±10o, followed by a 27-ft vertical section. The casing ID is 6-in., and a 2-in. ID tubing is placed with end-of-tubing at the bottom of vertical section. The casing and tubing streams are each led to a return column, where gas and liquid flows are metered. Automated and modulated control valves are used to monitor the pressure and production from casing and tubing streams. Five Coriolis flow meters quantify density and flow rate of different fluid streams. All of the equipment is connected to a control computer via DAQ cards.
The experiments are performed with air, supplied by a screw-type compressor, and water, supplied by a moyno pump. The experiments are conducted with different gas (Qg = 30-230 Mscfd) and liquid (QL = 17-700 bpd) flowrates to simulate the cases with both rod pump and ESP operations. The air-water ratio is increased for fixed water rates to identify the ranges of separator effectiveness. The tested downhole separator is an innovative design, applying gravity and centrifugal effects to perform the separation. The results indicate that average gas separation efficiency of the separator is 93% and average liquid separation efficiency is 96% over a wide range of operating conditions, as measured by return line flow meters for casing and tubing streams. The characteristics of multiphase flow in horizontal and vertical sections of the setup are observed and evaluated using surveillance cameras. The separator can be used widely in oil fields to improve gas-liquid separation and artificial lift performance.
The application of pumping artificial lift methods in high GOR wells can help significantly improve the production from a wide range of volatile oil and condensate wells. This illustrates the value of utilizing innovative downhole separation strategies. This paper presents one such centrifugal downhole separator and studies its performance in enhancing the production.
Wettability is an important petrophysical property, which governs irreducible fluid saturations, relative permeability, and fluid invasion. Unlike conventional reservoirs, which have relatively uniform pore-surface properties, the concept of wettability is questionable in organic-rich tight reservoirs. These rocks do not only have a nanoporous system, but also possess multiple pore types with different interfacial affinities. Previous studies have shown that the unconventional reservoirs consist of three major pore types: inorganic pores (assumed to be water-wet), organic pores (assumed to be oil-wet, controlled by organic matter and thermal maturity), and mixed-wet pores (controlled by organic-inorganic distribution) (Curtis et al., 2012). The current study revisits the concept of pore-type partitioning in tight rocks. We propose and demonstrate a new workflow to evaluate pore partitioning using four companion samples from Wolfcamp B Shale. First, all the specimens were vacuum dried at 100°C for 6 days to remove the free fluids until the weight stabilized. Total porosity was estimated as the sum of irreducible liquid volume (using nuclear magnetic resonance (NMR)) and gas-filled volume (using a high-pressure helium pycnometer). Two of the specimens were saturated with a single fluid (either dodecane or 2.5 wt% KCl brine) - first, via imbibition for 5 days, followed by step pressurization (up to 7,000 psi) to achieve 100% saturation. The imbibition step was done hydrostatically with fluid injected into the samples from all directions. The other companion specimens were subjected to multiple injection cycles - starting with imbibition, then counter imbibition, and finally, step pressurization with the replacing phase. During this process, we used brine-then-dodecane and dodecane-then-brine as the injection fluid sequences. The counter-imbibition process refers to the imbibition of the samples by one liquid followed by another liquid. All four samples were continuously monitored by both gravimetric and NMR measurements until equilibration. Relative fractions of both replaced and replacing phases were calculated from sample weights and pore-fluid volumes. The new approach classifies the connected pore network into three categories - oil-wet, water-wet, and mixed-wet, respectively, occupying 50, 15, and 35% of total movable pore volume in the Wolfcamp B. Mixed-wet pore is defined as the pore fraction, in which both oil and water can replace air under capillary suction. Using a conventional NMR wettability index, based on the difference between brine and oil intakes (Looyestijn and Hofman, 2006), this sample would appear to be oil-wet. However, this is a misleading interpretation. It is important to emphasize that mixed-wet pores are not equivalent to neutral-wet systems. We observe that the mixed-wet pores prefer brine over oil. During the counter-imbibition step, the samples initially imbibed with dodecane tend to intake brine while replacing dodecane, whereas the samples initially imbibed with brine and then counter imbibed with dodecane do not show a significant change in fluid concentrations. Instead, it required 1,500 psi of injection pressure for dodecane to reenter the pore system. During well completion, water blockage will likely happen in this formation due to the capillary preference of mixed-wet pores. This formation damage can be reduced by the addition of surfactants into fracturing fluids. Moreover, the effect of water blockage is expected to reduce with more than 1,500 psi of drawdown. Thus, the workflow is promising to fully describe the pore network in tight formations in which pore-type partitioning is a more reasonable concept than wettability.
Due to the extremely low permeability and high depletion rate, primary recovery from unconventional reservoirs is generally low. Huff-n-puff has proved to be a successful EOR technique in tight formations, such as the Eagle Ford. However, the underlying transport mechanism remains to be completely understood. Recent studies show oil-gas diffusion is a key factor for the success of huff-n-puff EOR. Due to concentration gradient, injected gas molecules diffuse into
Our research group has designed an experiment with a high pressure-high temperature cell having observation windows for the measurement of oil swelling and diffusivity in oil-gas mixtures and in this study, we present some preliminary results. The measurements were done on a Meramec oil (API-42.7) with 3 different gas mixtures of methane – ethane, at a temperature of 175°F to evaluate the impact of injection pressure (above and below Minimum Miscibility Pressure-MMP) and injectate composition on oil-gas diffusivity. The diffusivity of injectate gas into oil phase as a function of pressure increases to maximum at MMP, beyond which it decreases. Using pure methane (MMP = 5500 psi) as the injectate, the diffusion coefficient increases by 250% on increasing the pressure from 2500 psi to 5500 psi and then decreases. Based on the data available in the literature, this decrease in diffusivity can be explained by the increase in bulk fluid density and viscosity. For the oil sample used in this study, the diffusion coefficient varies between 10−10 m2/s to 10−9 m2/s, regardless of pressure and injectate composition.
Tight reservoirs generally have high matrix tortuosity, which impacts the diffusion efficiency in the porous media. Using tortuosity values available in the literature and diffusivities of oil gas systems measured in this study, we estimate that the injected gas can only travel 0.2-0.75 ft away from the fracture-faces in 1-6 months of injection. This study highlights the importance of stimulated reservoir area (SRA) characterization, nanoporous tortuosity and diffusivity measurements to optimize huff-n-puff recovery in shales.
Decline curve analysis has been used as a reliable method to forecast conventional reservoir well production over the last decades. Recently, an increase in the demand for oil and gas has caused unconventional reservoirs to become a prominent source of energy. However, it is challenged if we still apply the decline curve analysis in unconventional reservoirs due to its limitations such as boundary dominated flow, constant operation condition, et al. Therefore, in this paper, two new methods are proposed using machine learning method to forecast well production in unconventional reservoirs, especially on the EOR pilot projects.
The first method is the Neural Network, which allows the analysis of large quantities of data to discover meaningful patterns and relationships. Both peak production rate and hydraulic fracture parameters are used to be the key factors. Lastly, Neural Network technology is applied to investigate the relationship between key factors and oil production rate. The second method uses the Time Series Analysis. Time Series Analysis is one of the most applied data science techniques in business and finance. Since the properties of unconventional reservoir make the production prediction more difficult, it is safe to say that Time Series Analysis can yield good results on the production rate forecast.
Field production data from over 1000 wells from different shale plays (Barnett, Bakken, Bone Springs, Eagle Ford oil, Eagle Ford gas, Fayetteville, Marcellus gas, Marcellus oil, Utica oil, and Woodford) is used to verify the feasibility of these two methods. The results indicate there is a good match between the available and predicated production data. The overall R values of Neural Network and Time Series Analysis are above 0.8, which demonstrates that Neural Network and Time Series Analysis are reliable to study the dataset and provide proper production prediction. Meanwhile, when dealing with the EOR production prediction, such as Huff-n-Puff, Time Series Analysis shows more accurate results than Neural Network.
This paper proposes a thorough analysis of the feasibility of machine learning in multiple unconventional reservoirs. Instead of repeatedly fitting the production data by decline curve analysis, it also provides a more robust way and meaning reference for the evaluation of the wells.
Summary Unconventional reservoirs such as Wolfcamp and Eagle Ford formations have played an important role in boosting the oil and gas production in the United States, but unfortunately, primary recovery from these reservoirs seldom exceeds 10%. Thus, operators are exploring enhanced oil recovery (EOR) techniques such as miscible gas injection (huff ‘n’ puff) and surfactants to increase the production from shales. This study evaluates several commercial surfactants and the commonly used solvent limonene for their ability to increase hydrocarbon recovery. The results show that the various surfactants at 2 gallons per ton (gal/t) or 0.8 wt% concentration recover up to 29, 33, and 34% hydrocarbons from Lyons sandstone, Wolfcamp, and Eagle Ford rock samples, respectively. This is significantly more than the base case (no surfactants), which recovers only 16, 19, and 14%, respectively. The increased recovery by surfactants can be partially explained by the reduction in interfacial tension (IFT) between crude oil and brine (up to 90%) caused by the surfactant solutions. Another important reason governing the hydrocarbon recovery is the ability of the surfactants to prevent asphaltene precipitation. This study focused on the interaction of the surfactants with the asphaltenes and found some surfactants can cause a linear decrease in asphaltene precipitation with increasing surfactant concentration. Finally, the contact angle measurements were used to study the change in wettability of the rock surface caused by surfactant solutions that can preferentially change the oil‐wet and mixed‐wet pores to more water‐wet pores, thereby further aiding the hydrocarbon recovery. This study shows that an integrated approach including a broad spectrum of measurements such as aqueous stability, IFT, contact angle, phase behavior, spontaneous imbibition hydrocarbon recovery, and asphaltene precipitation is required to adequately characterize any surfactant and its ability to increase the hydrocarbon recovery.