Decline curve analysis is widely used in industry to perform production forecasting and to estimate reserves volumes. A useful technique in verifying the validity of a decline model is to estimate the Arps decline parameters, the loss ratio and the b-factor, with respect to time. This is used to check the model fit and to determine the flow regimes under which the reservoir produces. Existing methods to estimate the b-factor are heavily impacted by noise in production data. In this work, we introduce a new method to estimate the Arps decline parameters.
We treat the loss ratio and the b-factor over time as parameters to be estimated in a Bayesian framework. We include prior information on the parameters in the model. This serves to regularize the solution and prevent noise in the data from being amplified. We then fit the parameters to the model using Markov chain Monte Carlo methods to obtain probability distributions of the parameters. These distributions characterize the uncertainty in the parameters being estimated. We then compare our method with existing methods using simulated and field data.
We show that our method produces smooth loss ratio and b-factor estimates over time. Estimates using the three-point derivative method are not matched with data, and results in biased estimates of the Arps parameters. This can lead to misleading fits in decline curve analysis and unreliable estimates of reserves. We show that our technique helps in identification of end of linear flow and start of boundary dominated flow. We use our method on simulated data, with and without noise. Finally, we demonstrate the validity of our method on field cases.
Fitting a decline curve using the loss ratio and b-factor plots is a powerful technique that can highlight important features in the data and the possible points of failure of a model. Calculating these plots using the Bourdet three-point derivative induces bias and magnifies noise. Our analysis ensures that this estimation is robust and repeatable by adding prior information on the parameters to the model and by calibrating the estimates to the data.
This paper presents a simple yet rigorous model and provides a methodology to analyze production data from wells exhibiting three-phase flow during the boundary-dominated flow regime. Our model is particularly applicable to analyze production data from volatile oil reservoirs, and should replace the less accurate single-phase models commonly used. The methodology will be useful in rate transient analysis and production forecasting for horizontal wells with multiple fractures in shales. Our analytical model for efficiently handling multi-phase flow is an adaptation of existing single-phase models. We introduce new three-phase parameters, notably fluids properties. We also define three-phase material balance pseudotime and three-phase pseudopressure to linearize governing flow equations. This linearization makes our model applicable to wells with variable rates and flowing pressures. We optimized the saturation-pressure path and further suggested an appropriate method to calculate three-phase pseudopressures. We validated the solutions through comparisons with compositional simulation using commercial software; the excellent agreement demonstrated the accuracy and utility of the analytical solution. We concluded that, during the boundary-dominated flow regime, the saturation-pressure relation given by steady-state path and tank-type model for volatile oil reservoirs leads to satisfactory results. We also confirmed that our definitions of three-phase fluid properties are well suited for ultra-low permeability volatile oil reservoirs. The computation time of our model is greatly reduced compared to a numerical approach, and thus the methodology should be attractive to the industry. Our model is efficient and practical to be applied for production data analysis in ultra-low permeability volatile reservoirs with non-negligible water production during the boundary-dominated flow regime. This study extends existing analytical model methodology for volatile oil reservoirs and is relatively easy for reservoir engineers to understand.
Horizontal wells with hydraulic fractures enable economical hydrocarbon extraction from unconventional reservoirs, and the associated transient production data is a reliable source for reservoir characterization. However, the complicated convolution of rate-pressure-time history leads to a less informative analysis of true reservoir characteristics. This paper presents a novel data-driven deconvolution approach using physics-based superposition to reconstruct constant-rate-drawdown pressure responses, which are further translated into diagnostic plots for efficient production analysis.
Traditional deconvolution in pressure transient analysis is usually an ill-conditioned "inverse" process that requires systematic curve-fitting, and the deconvolution response is highly sensitive to noise. Our proposed approach uses superposition equations as training features to honor the transient physics, and further projects them into higher dimensional ‘reservoir’ space (kernel-space) for the purpose of rigorous regression. Additionally, by implementing Laplacian eigenmaps, our algorithm is relatively insensitive to noise owing to its locality-preserving character. After training, the constant-rate-drawdown pressure response is reconstructed and a diagnostic plot is generated to identify key reservoir characteristics such as flow regimes.
We first validated our approach with two synthetic cases, a horizontal well with single and multiple transverse fractures (MTFW), and the drawdown pressure responses were obtained through simulation using a highly variable flow rate history. Additionally, we added artificial white Gaussian noise to the simulation output to mimic measured signals collected in the field, and we input this data into our model for deconvolution. The model-reconstructed constant-rate-drawdown pressure responses were used to determine flow regimes and reservoir properties such as permeability and stimulated reservoir volume (SRV) using traditional transient testing diagnostic tools and specialized plots. The deconvolved responses for each case were in alignment with the fractured-basement reservoir model proposed by
This study showed that our proposed methodology is a reliable diagnostic tool to interpret pressure-rate data using traditional pressure transient analysis for unconventional reservoirs. Rapid and accurate deconvolved pressure responses greatly enhance the analysis of data with moderate noise and highly variable production histories, enabling engineers to recognize flow patterns and estimate reservoir properties. We demonstrated the versatility and applicability of our proposed approach with synthetic and field cases.
Qureshi, M Fahed (Texas A&M University at Qatar) | Ali, Moustafa (Texas A&M University) | Rahman, Mohammad Azizur (Texas A&M University at Qatar) | Hassan, Ibrahim (Texas A&M University at Qatar) | Rasul, Golam (Texas A&M University at Qatar) | Hassan, Rashid (Texas A&M University)
The hole cleaning is considered a key element of drilling operation as it impacts the economics of drilling operations, operational time of operations and the safety of operations. Inadequate hole cleaning can lead to blockages resulting in loss of circulation and premature wear out of the drill pipe. The transport of solids cuttings as a multiphase flow offers a solution to the hole cleaning issue, as it can aid to lower operational cost, reduce operation time, and enhance the quality of overall drilling operations.
Electrical resistance tomography (ERT) is a promising technology to visualize the 3D flow conditions involved in the hole cleaning process. ERT system is utilized to study and analyze the multiphase flow behavior and to provide in situ volume fraction distribution quantitatively through the drilling annulus. The motive of this work is to investigate the effect of different eccentricities (0-50 %), inner pipe rotation speed (0-120 RPM) and liquid flow rates (160-190 Kg/min) on the secondary phase (solids + air) transport across the annulus using the ERT system. The three-phase flow conditions (water, air, and solids) experiments were conducted in the horizontal flow loop with annulus at Texas A&M University at Qatar (TAMUQ) using ERT system. The flow loop annulus line consists of 6.16 m horizontal/inclined line. The inner diameter of the outer acrylic pipe and the outer diameter of the inner stainless steel pipe were 114.3 mm (4.5 in) and 63.5 mm (2.5 in), respectively. The glass beads (2-3 mm) were injected at a concentration of 5 wt%. The experimental results indicate that the ERT sensors have the capability of providing real-time quantitative images of annular multiphase flow regimes and it can be utilized effectively to observe the secondary phase (solids + air) transport across the opaque region of the annulus. It was also observed that the concentration of secondary phase (solids + air) tends to increase with an increase in the eccentricity of the inner pipe and the inner pipe rotation does not have a significant effect on the concentration of secondary phase (solids + air) at selected experimental conditions.
Fruchtnicht, Erich (Texas A&M University) | Eaker, Nancy (Texas A&M University) | Fellers, John (Texas A&M University) | Urbanczyk, Brad (Texas A&M University) | Robertson, Christina (Texas A&M University) | Dhakal, Merina (Spelman College) | Colman, Stephanie (Texas A&M University) | Freas-Lutz, Diana (Radford University) | Patterson, Hiram (Texas A&M University) | Bazan, Cristina (Texas A&M University) | Giles, Crystal (Texas A&M University)
THE TEXAS A&M HEALTH SCIENCE CENTER (TAMHSC) and Texas A&M University (TAMU) Environmental Health and Safety (EHS) departments are responsible for ensuring the safety of not only all faculty, staff, students and visitors to geographically dispersed campuses across the state of Texas, but also the public surrounding those campuses. Because the university is a state entity, the preferred disposition route for all university assets is public auction administered by the Surplus department. Each research or academic department within the university determines which of its assets are no longer needed and schedules a pickup through its embedded property management team member. The removal of all unwanted assets is performed either by university personnel or by a private moving company. Although EHS had a policy in place for the decontamination of equipment prior to its release to Surplus, the process of equipment being sent to Surplus itself did not directly include EHS.
Creating sufficient and sustained fracture conductivity contributes directly to the success of acid-fracturing treatments. The permeability and mineralogy distributions of formation rocks play significant roles in creating nonuniformly etched surfaces that can withstand high closure stress. Previous studies showed that, depending on the properties of formation rock and acidizing conditions (acid selection, formation temperature, injection rate, and contact time), a wide range of etching patterns (roughness, uniform, channeling) could be created that can dictate the resultant fracture conductivity. Insoluble minerals and their distribution can completely change the outcomes of acid-fracturing treatments. However, most experimental studies use homogeneous rock samples such as Indiana limestone that do not represent the highly heterogeneous features of carbonate rocks. This work studies the effect of heterogeneity and, more importantly, the distribution of insoluble rock on acid-fracture conductivity.
In this research, we conducted acid-fracturing experiments using both homogeneous Indiana limestone samples and heterogeneous carbonate rock samples. The Indiana limestone tests served as a baseline. The highly heterogeneous carbonate rock samples contain several types of insoluble minerals such as quartz and various types of clays along sealed natural fractures. These minerals are distributed in the form of streaks correlated against the flow direction, or as smaller nodules. After acidizing the rock samples, these minerals acted as pillars that significantly reduced conductivity-decline rate at high closure stresses. Both X-ray diffraction (XRD) and X-ray fluorescence (XRF) tests were performed to pinpoint the type and location of different minerals on the fracture surfaces. A surface profilometer was also used to correlate conductivity as a function of mineralogy distribution by comparing the surface scans from after the acidizing test to the scans after the conductivity test. Theoretical models considering geostatistical correlation parameters were used to match and understand the experimental results.
Results of our study showed that insoluble minerals with higher-strength mechanical properties were not crushed at high-closure stress, resulting in a less-steep conductivity decline with an increasing closure stress. If the acid etching creates enough conductivity, the rock sample can sustain a higher closure stress with a much lower decline rate compared with Indiana limestone samples. Fracture surfaces with insoluble mineral streaks correlated against the flow direction offer the benefit of being able to maintain conductivity at high closure stress, but not necessarily high initial conductivity. Using a fracture-conductivity model with correlation length, we matched the fracture-conductivity behavior for the heterogeneous samples. Fracture surfaces with mineral streaks correlated with the flow direction could increase acid-fracturing conductivity significantly as compared to the case when the streak is correlated against the flow direction.
The results of the study show that fracture conductivity can be optimized by taking advantage of the distribution of insoluble minerals along the fracture surface and demonstrate important considerations to make the acid-fracturing treatment successful.
The standard modeling techniques for fractured wells were developed for conventional (higher permeability) reservoirs. The application of these techniques in fractal (shale) reservoirs often yield physically-inconsistent results which can cause over/mis-interpretation of the transient data. The purpose of this work is to provide a new modeling scheme using the "fractional integration" solution for hydraulically fractured wells producing from a fractal reservoir. This methodology takes into account the reservoir heterogeneity in the modeling of the fluid flow towards the hydraulic fracture and provides physically consistent diagnostic interpretations and parameters.
We have used the "fractional integration" approach to "couple" the fluid flow from a fractal (reservoir) to a Euclidean object (
In this work we derive generalized models that can reproduce the classic Euclidean hydraulic fracture scenarios. We studied the constant-rate and constant-pressure cases and found that our proposed models yield the following three flow periods:
Period 1: Early Fractal-Formation (EFF) flow. This flow period is analogous to the formation-linear flow for conventional reservoirs. The transient signature of this flow period is only influenced by the conductivity index (reservoir heterogeneity fractal parameter).
Period 2: Late Fractal-Formation (LFF) flow. This flow period can also be observed in conventional reservoirs, although its characteristics are not extensively documented in the existing literature. This period is influenced by the fracture length and the reservoir fractal parameters,
Period 3: Pseudo-Fractal (PF) Flow. This is analogous to the pseudo-radial flow regime for conventional reservoirs. The transient performance behavior of this flow period depends on the two reservoir fractal parameters defined in this work.
In performing this work, we provide the following technical contributions:
We introduce a physically-consistent modeling scheme for a well with uniform-flux vertical fracture producing from a fractal (shale) reservoir.
We show that the transient flow behavior for a well intercepting a uniform-flux vertical fracture can exhibit three distinct flow periods.
We provide field demonstration cases which are analyzed and interpreted using the new solutions presented in this work.
Observations from pilot wells along with laboratory experiments have revealed the significant potential of CO2 as an EOR agent in unconventional liquid reservoirs (ULR). This study focuses on unveiling the mechanisms of gas injection EOR through a combination of experimental results, ternary diagram analysis, and core-scale simulation. In addition, laboratory results were upscaled to the field-scale to evaluate the effectiveness of the CO2 injection in production enhancement from ULR.
Gas injection experiments were performed at different pressures, and the laboratory results were upscaled to evaluate the production enhancement through gas injection EOR in ULR. A CT-generated core-scale model was utilized to investigate the mechanisms of gas injection EOR. Mechanisms such as diffusion and multi-contact miscibility were determined from core-scale simulation through history-matching experimental results, then upscaled to the field-scale model. Ternary diagrams reveal that EOR by gas injection is only effective at pressures greater than the Minimum Miscibility Pressure (MMP). Alteration of the injected gas and composition of crude oil clearly has an implication on changing the ternary diagram.
The primary production mechanisms of CO2 EOR are multi-contact miscibility, vaporizing/condensing gas drive, oil swelling, and diffusion. Gas injection experiments recovered up to 45% of the Original Oil In Place (OOIP) at 3,500 psi, but the recovery factor was less than 5% when operating below the MMP. Diffusion has a minor effect in enhancing oil recovery in ULR based on the core-scale history-matching results. The multi-contact miscibility is found to be the primary driving mechanism for oil extraction during gas injection. Ternary diagrams analysis clearly demonstrates that MMP plays a significant role in gas injection and that miscible conditions need to be achieved for EOR projects in ULR. CT-scan technology is utilized to demonstrate the movement of the fluids inside the cores throughout the experiments. Thus, we can determine the high flow path regions of the core plugs. Additionally, the impact of injection pressure and the start time of the gas injection process were analyzed using the field-scale model. The simulation results indicate that gas injection has significant potential of enhancing oil production in ULR. This study not only reveals the mechanisms of gas injection in ULR, but also provides a method for designing and optimizing gas injection for Huff-n-Puff EOR.
This study challenges the paradigm that diffusion is the dominating parameter of CO2 injection EOR in ULR. The novelty comes from the establishment of gas injection EOR mechanism in ULR through a thorough analysis of laboratory experiments, core-scale simulation, and ternary diagram analysis. In addition, a new modeling workflow for the design of gas injection strategies is proposed to unveil the real potential of gas injection.
Wu, Yonghui (China University of Petroleum-Beijing, and Texas A&M University) | Cheng, Linsong (China University of Petroleum-Beijing) | Killough, John E. (Texas A&M University) | Huang, Shijun (China University of Petroleum-Beijing) | Fang, Sidong (Sinopec Exploration and Production Research Institute) | Jia, Pin (China University of Petroleum-Beijing) | Cao, Renyi (China University of Petroleum-Beijing) | Xue, Yongchao (China University of Petroleum-Beijing)
The large uncertainty in fracture characterization for shale gas reservoirs seriously affects the confidence in making forecasts, fracturing design, and taking recovery enhancement measures. This paper presents a workflow to characterize the complex fracture networks (CFNs) and reduce the uncertainty by integrating stochastic CFNs modeling constrained by core and microseismic data, reservoir simulation using a novel edge-based Green element method (eGEM), and assisted history matching based on Ensemble Kalman Filter (EnKF).
In this paper, the geometry of CFNs is generated stochastically constrained by the measurements of hydraulic fracturing treatment, core, and microseismic data. A stochastic parameterization model is used to generate an ensemble of initial realizations of the stress-dependent fracture conductivities of CFNs. To make the eGEM practicable for reservoir simulation, a steady-state fundamental solution is applied to the integral equation, and the technique of local grid refinement (LGR) is applied to refine the domain grids near the fractures. Finally, assisted-history-matching based on EnKF is implemented to calibrate the DFN models and further quantify the uncertainties in the fracture characterization.
The proposed technique is tested using a multi-stage fractured horizontal well from a shale gas field. After analyzing the history matching results, the proposed integrated workflow is shown to be efficient in characterizing fracture networks and reducing the uncertainties. The advantages are exhibited in several aspects. First, the eGEM-based Discrete-Fracture Model (DFM) is shown to be quite efficient in assisted history matching of large field applications because of eGEM’s high precision with coarse grids. This enables simulations of CFNs without upscaling the fractures using continuum approaches. In addition, CFNs geometry can be generated with the constraints of core and microseismic data, and a primary conductivity of CFNs can be generated using the hydraulic fracturing treatment data. Moreover, the uncertainties for CFNs characterization and EUR predictions can be further reduced with the application of EnKF in assimilating the production data.
This paper provides an efficient integrated workflow to characterize the fracture networks in fractured unconventional reservoirs. This workflow, which incorporated several efficient techniques including fracture network modeling, simulation and calibration, can be readily used in field applications. In addition, various data sources could be assimilated in this workflow to reduce the uncertainty in fracture characterization, including hydraulic fracturing treatment, core, microseismic and production data.
As exploration for oil and gas continues, it becomes necessary to produce from deeper formations, have low permeability, and higher temperature. Unconventional shale formations utilize slickwater fracturing fluids due to the shale’s unique geomechanical properties. On the other hand, conventional formations require crosslinked fracturing fluids to properly enhance productivity.
Guar and its derivatives have a history of success in crosslinked hydraulic fracturing fluids. However, they require higher polymer loading to withstand higher temperature environments. This leads to an increase in mixing time and additive requirements. Most importantly, due to the high polymer loading, they do not break completely and generate residual polymer fragments that can plug the formation and reduce fracture conductivity significantly.
In this work, a new hybrid dual polymer hydraulic fracturing fluid is developed. The fluid consists of a guar derivative and a polyacrylamide-based synthetic polymer. Compared to conventional fracturing fluids, this new system is easily hydrated, requires fewer additives, can be mixed on the fly, and is capable of maintaining excellent rheological performance at low polymer loadings.
The polymer mixture solutions were prepared at a total polymer concentration of 20 to 40 lb/1,000 gal and at a volume ratio of 2:1, 1:1, and 1:2. The fluids were crosslinked with a metallic crosslinker and broken with an oxidizer at 300°F. Testing focused on crosslinker to polymer ratio analysis to effectively lower loading while maintaining sufficient performance to carry proppant at this temperature. HP/HT rheometer was used to measure viscosity, storage modulus, and fluid breaking performance. HP/HT aging cell and HP/HT see-through cell were utilized for proppant settling. FTIR, Cryo-SEM and HP/HT rheometer were also utilized to understand the interaction.
Results indicate that the dual polymer fracturing fluid is able to generate stable viscosity at 300°F and 100 s-1. Results show that the dual polymer fracturing fluid can generate higher viscosity compared to the individual polymer fracturing fluid. Also, properly understanding and tuning the crosslinker to polymer ratio generates excellent performance at 20 lb/1,000 gal. The two polymers form an improved crosslinking network that enhances proppant carrying properties. It also demonstrates a clean and controlled break performance with an oxidizer.
Extensive experiments were pursued to evaluate the new dual polymer system for the first time. This system exhibits a positive interaction between polysaccharide and polyacrylamide families and generates excellent rheological properties. The major benefit of using a mixed polymer system is to reduce polymer loading. Lower loading is highly desirable because it reduces material cost, eases field operation and potentially lowers damage to the fracture face, proppant pack, and formation.