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Liu, Hongtao (PetroChina Tarim Oilfield Company) | Wang, Haotian (University of Texas at Austin) | Zhang, Wei (PetroChina Tarim Oilfield Company) | Liu, Junyan (PetroChina Tarim Oilfield Company) | Zhang, Yutao (Chengdu Zhongpu Oil & Gas Technology Co., Ltd.) | Sharma, Mukul M. (University of Texas at Austin)
Sand production has been a very serious concern for the high-pressure, high-temperature (HPHT) gas wells in the Tarim Basin. However, the possible reasons and mechanisms remain unclear because there is no sufficient model to predict both onset of sanding and sand-production rate. The objective of this study is to develop a three-dimensional (3D) numerical sand production-prediction model and apply it to these HPHT gas wells to determine the main mechanisms for sand production and to propose completion designs to minimize sand production. This paper presents the development of a fully coupled 3D, poro-elasto-plastic sand-production model and the simulation results for two key wells that are prone to sanding.
The sand-production model was used to model the different completion designs and flowback strategies that were used in the field. The model couples multiphase fluid flow and elasto-plasticity to simulate pressure transient behavior and rock deformation during production. The sanding criterion is a combination of both mechanical failure (shear/tensile/compressive failure) and fluid erosion. A novel cell-removal algorithm has been implemented to predict the dynamic (time dependent) sand-production process. In addition, the complex geometry of the wells and perforations are explicitly modeled to show cavity propagation around hole/perforations during sand production.
For this case study, triaxial tests on core samples were conducted, and the stress-strain curves under different confining stresses are analyzed to obtain rock properties for both the preyield and post-yield period. The wells were categorized into ones that had massive sand production and ones that showed much less sand production. Operational and mechanical factors that were empirically found to result in sand production were identified. The sand-production model was run to verify the role played by different factors. It is shown that completion design, rock strength, and post-failure behavior of the rock are key factors responsible for the observed sanding in these wells. In addition, the drawdown strategy and the associated bottomhole pressure (BHP) change and the extent of depletion play an important role in the sanding rate. Several strategies for minimizing sand production are suggested for these wells. These include drawdown management, completion, and perforation design. In this study, we show for the first time that data from HPHT gas wells that have severe sand-production problems can be analyzed quantitatively with the developed model to determine the mechanisms of sand production. This allows us to make operational recommendations to minimize sanding risk in these wells.
Summary Fracture closure and proppant settling are two fully coupled processes during both shut-in and production. Proppant distribution greatly affects the residual fracture width and conductivity evolution, whereas fracture closure might limit proppant settling and force the proppant to crush or embed into the rock. Modeling fracture closure with proppant settling and embedment is challenging because of the multiple coupled physical processes involved, large timescale differences, and extreme nonlinearity in the coupling of the processes. Conventional fracture-closure models either use simplified analytical estimates of the stress-dependent permeability of the reservoir or explicitly calculate the fracture width using empirical relationships, without considering the effect of fluid leakoff and dynamic changes in the proppant distribution in the fracture. In this work, we use a novel fully implicitly coupled fracturing/reservoir simulator to study fracture closure and proppant-settling/embedment processes during shut-in and production. During shut-in, a modified Barton-Bandis (Bandis et al. 1983) formula is used to describe the nonlinear relationship between the contact force and the residual fracture aperture considering the dynamic proppant spatial distribution and rock heterogeneity. During production, fracture conductivity is evaluated according to proppant distribution and further fracture closure caused by proppant crushing and embedment. A Newton-Raphson method is applied to solve the coupled system of equations. Results from the simulations clearly show that typical periods of shut-in after fracturing lead to the formation of proppant banks at the bottom of the fracture in low-permeability, low-leakoff formations. This can lead to near-wellbore tortuosity and poor connectivity between the wellbore and the hydraulic-fracture network. Stress-dependent permeability, likely induced by induced unpropped fractures, is shown to be essential to obtain reasonable values of leakoff and to history match production trends. Proppant embedment is shown to be an important factor controlling production-decline rates in clay-rich shales.
The oil and gas industry uses production forecasts to make decisions, which can be as mundane as whether to change the choke setting on a well, or as significant as whether to develop a field. These forecasts yield cash flow predictions and value-and-decision metrics such as net present value and internal rate of return.
In this paper, probabilistic production forecasts made at the time of the development final investment decisions (FIDs) are compared with actual production after FIDs, to assess whether the forecasts are optimistic, overconfident, neither, or both.
Although biases in time-and-cost estimates in the exploration and production (E&P) industry are well documented, probabilistic production forecasts have yet to be the focus of a comprehensive, public study. The main obstacle is that production forecasts for E&P development projects are not publicly available, even though they have long been collected by the Norwegian Petroleum Directorate (NPD), a Norwegian government agency. The NPD’s guidelines specify that at the time of FID, the operators should report the forecasted annual mean and P10/90 percentiles for the projected life of the field.
We arranged to access the NPD database in order to statistically compare annual production forecasts given at the time of FID for 56 fields in the 1995 to 2017 period, with actual annual production from the same fields. This work constitutes the first public study of the quality of probabilistic production forecasts. The main conclusions are that production forecasts that are being used at the FID for E&P development projects are both optimistic and overconfident, leading to poor decisions.1
1The conclusions based on the analysis presented in this paper are limited to the set of fields from the NCS. However, other authors have demonstrated the optimism bias in production forecasts from fields around the world (Nandurdikar and Wallace 2011; Nandurdikar and Kirkham 2012).
Posenato Garcia, Artur (University of Texas at Austin) | Jagadisan, Archana (University of Texas at Austin) | Hernandez, Laura M. (University of Texas at Austin) | Heidari, Zoya (University of Texas at Austin) | Casey, Brian (University Lands) | Williams, Richard (University Lands)
Summary Reliable formation evaluation in organic-rich mudrocks requires integrated interpretation of well logs and core measurements. More than 80% of the Permian Basin wells have incomplete data sets, lacking photoelectric factor (PEF) or other logs required for reliable formation evaluation in the presence of complex mineralogy. Hence, we develop a novel workflow to reliably estimate rock properties in wells with incomplete data to enhance reservoir characterization and completion decisions. We propose to use integrated rock classification for enhanced physics-based assessment of rock properties in wells with missing data; combine field-scale geostatistical and machine learning methods to reliably reconstruct missing PEF logs with a confidence interval through a rock-type-based approach, which is a unique contribution of this work; and quantify the uncertainty in estimates of petrophysical properties. We performed a preliminary field-scale formation evaluation on wells with triple-combo logs (more than 70 wells). Next, we performed an initial rock typing and reconstructed the missing PEF logs by combining supervised neural networks with geostatistical analysis on a rock-type basis. We then used an unsupervised neural network method to improve the rock classification based on the updated estimates of petrophysical and compositional properties after PEF reconstruction. The combined rock classification and PEF reconstruction was performed iteratively to improve the multimineral analysis results in all wells with missing data. We successfully applied the new workflow to 20 wells in blind tests. The reconstructed well logs agreed with the actual measurements with relative errors of less than 10%. The new workflow extends the boundaries of reliable formation evaluation, enabling accurate reservoir characterization and completion decisions by enhancing evaluation of wells with missing data. The proposed method can also be applied to wells with other types of missing data.
Lara Orozco, Ricardo A. (University of Texas at Austin) | Abeykoon, Gayan A. (University of Texas at Austin) | Wang, Mingyuan (University of Texas at Austin) | Arguelles-Vivas, Francisco (University of Texas at Austin) | Okuno, Ryosuke (University of Texas at Austin) | Lake, Larry W. (University of Texas at Austin) | Ayirala, Subhash C. (Saudi Aramco) | AlSofi, Abdulkareem M. (Saudi Aramco)
Reservoir wettability plays an important role in waterflooding, especially in fractured carbonate reservoirs since oil recovery from the rock matrix is inefficient because of their mixed wettability. This paper presents the first investigation of amino acids as wettability modifiers that increase waterflooding oil recovery in carbonate reservoirs.
All experiments used a heavy-oil sample taken from a carbonate reservoir. Two amino acids were tested, glycine and ß-alanine. Contact angle experiments with oil-aged calcite were conducted at room temperature with deionized (DI) water, and then at 368 K with three saline solutions: 243 571-mg/L salinity formation brine (FB), 68 975-mg/L salinity injection brine 1 (IB1), and 6898-mg/L salinity injection brine 2 (IB2). IB2 was made by dilution of IB1.
The contact angle experiment with 5-wt% glycine solution in FB (FB-Gly5) resulted in an average contact angle of 50°, in comparison to 130° with FB, at 368 K. Some of the oil droplets were completely detached from the calcite surface within a few days. In contrast, the ß-alanine solutions were not effective in wettability alteration of oil-aged calcite with the brines tested at 368 K.
Glycine was further studied in spontaneous and forced imbibition experiments with oil-aged Indiana limestone cores at 368 K using IB2 and three solutions of 5 wt% glycine in FB, IB1, and IB2 (FB-Gly5, IB1-Gly5, and IB2-Gly5). The oil recovery factors from the imbibition experiments gave the Amott index to water as follows: 0.65 for FB-Gly5, 0.59 for IB1-Gly5, 0.61 for IB2-Gly5, and 0.33 for IB2. This indicates a clear, positive impact of glycine on wettability alteration of the Indiana limestone cores tested.
Two possible mechanisms were explained for glycine to enhance the spontaneous imbibition in oil-wet carbonate rocks. The primary mechanism is that the glycine solution weakens the interaction between polar oil components and positively charged rock surfaces when the solution pH is between glycine’s isoelectric point (pI) and the surface’s point of zero charge (pzc). The secondary mechanism is that the addition of glycine tends to decrease the solution pH slightly, which in turn changes the carbonate wettability in brines to a less oil-wet state.
The amino acids tested in this research are nontoxic and commercially available at relatively low cost. The results suggest a new method of enhancing waterflooding, for which the novel mechanism of wettability alteration involves the interplay between amino acid pI, solution’s pH, and rock’s pzc.
Sheng, Kai (University of Texas at Austin) | Argüelles-Vivas, Francisco J. (University of Texas at Austin) | Baek, Kwang Hoon (University of Texas at Austin) | Okuno, Ryosuke (University of Texas at Austin)
Summary Water is the dominant component in steam-injection processes, such as steam-assisted gravity drainage (SAGD). The central hypothesis in this research is that in-situ oil transport can be enhanced by generating oil-in-water emulsion, where the water-continuous phase acts as an effective oil carrier. As part of the research project, this paper presents an experimental study of how oil-in-water emulsion can improve oil transport in porous media at elevated temperatures. Diethylamine (DEA) was selected as the organic alkali that generates oil-in-water emulsions with Athabasca bitumen at a 1,000-ppm NaCl brine and a 0.5-wt% alkali concentration. This aqueous composition had been confirmed to be an optimum in terms of oil content in the water-external emulsion phase at a wide range of temperatures. Then, flow experiments with a glass-bead pack were conducted to measure the effective viscosities of emulsion samples at shear rates from 5 to 29 seconds 1 at 35 bar and temperatures from 373 to 443 K. Results show that the oil-in-water emulsions were more than 15 times less viscous than the original bitumen at temperatures from 373 to 443 K. At the shear rate of 5 seconds 1, for example, the emulsion viscosity was 12 cp at 373 K, at which the bitumen viscosity was 206 cp. The efficiency of in-situ bitumen transport was evaluated by calculating the bitumen molar flow rate under gravity drainage with the new experimental data. Results show that oil-in-water emulsion can enhance the in-situ molar flow of bitumen by a factor of 273 at 403 K and 345 at 373 K, in comparison with the two-phase flow of oil and water in conventional SAGD. At 443 K, only a fraction of bitumen is emulsified in water, but the bitumen transport by both oil-in-water emulsion and an excess oil phase in DEA-SAGD can enhance the molar flow of bitumen by a factor of 19 in comparison to SAGD. This is mainly because the mobility of the bitumen-containing phase is enhanced by the reduced viscosity and increased effective permeability. A marked difference between alkaline solvents and conventional hydrocarbon solvents is that only a small amount of an alkaline solvent enables enhancing the in-situ transport of bitumen. Introduction SAGD is the in-situ recovery technique widely used for bitumen production.
The wettability of organic-rich mudrocks has a significant effect on multiphase-fluid flow and hydrocarbon recovery. This important rock property has still not been well-quantified in organic-rich mudrocks. Kerogen constitutes a significant fraction of mudrocks and can considerably affect their wettability. Recent publications suggested that kerogen wettability is affected by the thermal maturity of rocks and can influence the wettability of mudrocks. In this paper, we experimentally quantify the influence of geochemistry and thermal maturity of kerogen on the wettability of organic-rich mudrocks, and the influence of thermal maturity and chemical bonding on the wettability of kerogen. The wettability of organic-rich-mudrock samples at different experimental thermal-maturity levels was measured using the sessile-drop method, and also qualitatively estimated using a Flotation test and spontaneous-imbibition experiments on crushed-organic-rich-mudrock samples. The concentration of minerals in the mudrock samples was quantified using X-ray diffraction (XRD) at different experimental maturity levels. We then isolated kerogen samples from an organic-rich-mudrock formation and experimentally matured them. The variation in the chemical-bonding state of carbon present in kerogen at different levels of natural and experimental thermal maturity was determined using X-ray-photoelectron-spectroscopy (XPS) measurements. Finally, the wettability of pure-kerogen samples at different thermal-maturity levels was quantified using the sessile-drop method and the effect of aromatic carbon content on the wettability of the kerogen samples was determined.
The sessile-drop test performed on the organic-rich-mudrock-rock samples showed a 5° increase in contact angle with a 96% decrease in the hydrogen index (HI). The Flotation test showed that the oil-wet fraction of the mudrock samples increases by 81% as the heat-treatment temperature increases from nonheated to 650°C. The water-imbibition measurements in crushed-mudrock samples suggest that the volume of water imbibed was higher by 22 cm3 at lower thermal maturity [i.e., HI of 328 mg hydrocarbon/g organic carbon (mg HC/g OC)] compared with mudrock samples at higher thermal maturity (i.e., HI of 10 mg HC/g OC). Results indicate that the thermal maturity of kerogen could potentially affect the wettability of mudrocks and that the mudrock has higher water wettability at lower thermal maturity of kerogen. The experimental results also demonstrated that the wettability of kerogen changes from waterwet to hydrocarbon-wet with an increase in the aromatic carbon content. The contact angle of the water droplet on the kerogen samples from Formation A increased by 78° when the aromatic carbon concentration increased by 19%. The results contribute to a better understanding of the effects of kerogen wettability and thermal maturity on the wettability of organic-rich mudrocks. The outcomes can also have potential future contributions in understanding flow mechanisms in organic-rich mudrocks as well as in developing reliable rockphysics models for the interpretation of borehole geophysical measurements [e.g., electromagnetic and nuclear-magnetic-resonance (NMR) measurements] in organic-rich mudrocks.
Chiotoroiu, Maria-Magdalena (OMV E&P) | Clemens, Torsten (OMV E&P) | Zechner, Markus (OMV E&P) | Hwang, Jongsoo (University of Texas at Austin) | Sharma, Mukul M. (University of Texas at Austin) | Thiele, Marco (Streamsim)
Summary Waterflooding can lead to substantial incremental oil production. Implementation of water-injection projects requires the project to fit into the risk (defined here as negative outcomes relative to defined project objectives) and uncertainty (defined here as the inability to estimate a value precisely) a company is willing to take. One of the key risks for water injection into a shallow reservoir is injection-induced fractures extending into the caprock. In this study, we evaluated caprock integrity by conducting simulations of long-term water injection that include the effects of formation damage caused by internal/external plugging, geomechanical stress changes, and fracture propagation in the sandstone and bounding shale. The risk of fracture growth into the caprock was assessed by conducting Latin hypercube sampling considering a set of modeling parameters each associated with an uncertainty range. This allowed us to identify the range of operating parameters in which the risk of fracture-height growth was acceptable. Our simulations also allowed us to identify important factors that affect caprock integrity. To cover the uncertainty in geomechanical reservoir evaluation, the operating envelope is identified such that the risk to the caprock integrity is reduced. This requires introducing a limit for the bottomhole pressure (BHP), including a safety margin. The limit of the BHP is then used as a constraint in the uncertainty analysis of water injectivity. The uncertainty analysis should cover the various development options, the parameterization of the model, sampling from the distribution of parameters-and distancebased generalized sensitivity analysis (dGSA) as well as probabilistic representation of the results. The results indicate that the time to reach the BHP limit varies substantially, dependent on the chosen development scenario.
Summary Heel-dominated treatment distribution among multiple perforation clusters is frequently observed in plug-and-perforate (plug-and-perf) stages, causing small propped surface areas, suboptimal production, and unexpected fracture hits. A multifracture simulator with a novel wellbore-fluid and proppant-transport model is applied to quantify treatment distribution among multiple perforation clusters in a plug-and-perf operation. A simulation base case is set up on the basis of a field treatment design with four clusters. Simulation results show that the two toe-side clusters screened out early in the treatment and the two heelside clusters were dominant. The simulated proppant placement is consistent with distributed-acoustic-sensing observations. The impact of different perforating strategies and pumping schedules on final treatment distribution is investigated. An optimal plug-and-perf design is defined as one that minimizes the SD of the treatment distribution among perforation clusters, and maximizes the PSA. Both perforating strategy and pumping schedule are found to affect the final treatment distribution significantly, and uniform treatment distribution is shown to create more PSA. Having fewer perforations per cluster was found to promote uniform fluid and proppant placement. Other helpful strategies include reducing the number of perforations near the heel and using small, lightweight proppant. The stress shadow effect is accounted for using the displacement discontinuity method (DDM) and was found to play a smaller role than perforation friction and proppant inertia in most cases. An automated process is developed to optimize plug-and-perf completion design with multiple decision variables using a genetic algorithm (GA). Thirteen parameters are optimized simultaneously. The optimal design solution creates an almost even treatment distribution and more than doubles the PSA compared with the base case. The multifracture model presented in this paper provides a way to quantify fluid and proppant distribution for any perforating strategy and pumping schedule, and provides more insight into the physics relevant to plug-and-perf treatment distribution. The perforation and pumping schedule recommendations presented in this paper provide directional guidance for the design of fracturing jobs with balanced treatment distribution and large PSA. Introduction plug-and-perf completions have been widely used in unconventional wells because of their cost-effectiveness.
Nuclear magnetic resonance (NMR) measurements have been attractive options for wettability characterization of reservoir rocks as they are sensitive to the type of fluid in contact with the grain surface. Several NMR-based wettability indices are documented in previous publications. Most of these methods require extensive calibration or involve complex inversion algorithms, which makes them computationally expensive and complicates their applicability in mixed-wet multimodal rocks. In this paper, we introduce a new NMR-based wettability index and verify its reliability in pore-scale and core-scale domains using numerical simulations and experimental measurements, respectively. This new index requires calibration at fully water-saturated water-wet and fully hydrocarbon-saturated hydrocarbon-wet states and can be applied to mixed-wet rocks at any fluid saturation level.
This new NMR-based wettability index is a function of the transverse magnetization (T2) of mixed-wet rocks, the bulk relaxivity and saturation of each fluid, and the T2 distributions for fully water-wet and hydrocarbon-wet samples of the same rock type. The reliability of the new index was first tested in the pore-scale domain. For this part, we selected several pore-scale microcomputed tomography (CT) images of carbonate and sandstone rocks. We used a previously developed finite volume simulator to model the T2 responses in these images at fully water-wet and fully hydrocarbon-wet wettability states. Then we generated synthetic partially saturated mixed-wet samples and simulated T2 responses in these synthetic images. We used the simulated T2 results for determining their NMR-based wettability index and verified its applicability in the pore-scale domain.
Next, we tested the reliability of the new NMR-based wettability index in the core-scale domain using NMR measurements in four Texas Cream (TC) rock samples, obtained from the Edwards formation. We altered the wettability of the cores to be water-, hydrocarbon-, and mixed-wet by injecting brine, a naphthenic acid in decane solution, or an anionic surfactant solution. We quantified the wettability of these samples using the Amott-Harvey (AH) index and contact angle measurements. Next, we measured the T2 distribution of these samples at different fluid saturation levels. Finally, we quantified the wettability values of these core samples using the new NMR-based index and compared them to those obtained from the AH index and contact angle measurements. We documented successful verification of the proposed method on samples with wettability ranging from –0.90 to 0.98 and from –0.6 to 0.5 (independently quantified using the AH method) in the pore- and core-scale domains, respectively. Results demonstrated that the new NMR-based wettability index reliably estimates the wettability of mixed-wet rocks in a wide range of wettability states. The new wettability index can potentially improve the speed and reliability of NMR-based wettability characterization and is promising for log-scale wettability assessment in mixed-wet rocks.