The Marcellus formation has begun to attract more attention from the oil and gas industry. Despite being the largest shale formation and biggest source of natural gas in the United States, it has been the subject of little research. To fill this gap, this study experimentally examined the rock properties of twenty core samples from the formation.
Five tests were performed on the core samples: X-ray computerized tomography (CT) scan, porosity, permeability, ultrasonic velocity, and X-ray diffraction (XRD). CT-scans were performed to identify the presence of any existing fracture(s). Additionally, helium was injected into the core samples at four different pressures (100 psi, 200 psi, 300 psi, and 400 psi) to determine the optimal pressure for porosity measurements. Complex Transient Method was employed to measure the permeabilities of the core samples. Ultrasonic velocity tests were conducted to calculate the dynamic Young's moduli (E) and the Poisson's ratios (ν) of the core samples at various confining pressures (in increments of 750 psi between 750 psi and 4,240 psi). Finally, the mineralogical compositions of the core samples were determined using the XRD test.
The results of the CT-scan experiments revealed that seven core samples contained fractures. The porosity tests yielded an optimal pressure of 200 psi for porosity measurement. The measured porosities of the samples were between 6.43% and 13.85%. The permeabilities of the samples were between 5 nD and 153 nD. The results of the ultrasonic velocity tests revealed that at the confining pressure of 750 psi, the compressional velocity (Vp) ranged from 18,411 ft/s to 19,128 ft/s and the average shear velocities (Vs1 and Vs2) ranged from 10,413 ft/s to 11,034 ft/s. At the same confining pressure, the Young's modulus and Poisson's ratio ranged from 9.8 to 10.8 million psi and 0.25 to 0.28, respectively. Increase in the confining pressure resulted in increases in the Vp, Vs, Young's moduli, and Poisson's ratios of the samples. The results of the XRD test revealed that the samples were composed of calcite, quartz, and dolomite.
This study is one of the first to characterize core samples obtained from the formation outcrop by performing five tests: CT-scan, porosity, permeability, ultrasonic velocity, and XRD. The results provide detailed insights to researchers working on the formation rock properties.
Though seemingly straightforward, the concept of "net-to-gross" (NTG) is often a source of confusion. Its proper use is still being debated in some portions of the oil and gas industry. NTG is a method to account for non-reservoir quality rock when calculating oil volumes within a reservoir. This is normally accomplished by applying cutoffs to calculated quantities, such as porosity, which then get excluded from the volumetric calculation. To the extent there have been recent discussions of this, the focus has been primarily on how to determine appropriate cutoffs. There has been very little mention of the implications of using NTG in flow equations within a reservoir simulator. The paper discusses the derivation and implied assumptions for the simulator NTG formulation and possible errors and proposes modifications to account for inconsistencies.
Resolving the NTG flow equations can be viewed as an upscaling problem, subject to implied assumptions about reservoir continuity. Many fine-scale reservoir simulations were run to test this and to calibrate the NTG equations. The underlying attributes were sampled from a bimodal distribution, which represent pay and non-pay. The results show the effects of NTG ratio, values of fine-scale attributes and spatial correlation on steady state, single phase effective permeability and immiscible flow displacements. They demonstrate errors in effective horizontal and vertical permeability when using NTG within a simulator. These errors cause potentially significant differences in production responses between underlying detailed fine-scale models and coarser models. The results demonstrate a possible need for corrections to the simulator net-to-gross formulations due to underlying implied assumptions and inconsistencies. Some possible modifications are also presented. Both standard and machine learning techniques were used to analyze the results.
Minagish Oolite reservoir is a prolific limestone reservoir in Umm Gudair field underlain by an active aquifer situated in West Kuwait. The field has been on production for over 50 years and has been experiencing rising water production levels in the recent years. Understanding the movement of water in the reservoir is vital for maximizing oil recovery.
During the producing life of the reservoir, the vertical movement of water is influenced by presence of flow barriers / baffles in the reservoir and how they are distributed in the vertical as well as areal direction. Understanding the lateral distribution of the flow barriers to fluid movement in the vertical direction has been a challenge throughout the production history of the field. Efforts have been ongoing in the past, to understand the movement of aquifer water in the vertical direction based on analysis of openhole log data, structural configuration, stratigraphy, well performance, production logging (PLT) results etc. These have resulted in developing a respectable level of understanding of the distribution and strength of barriers/baffles and their effectiveness in the field performance.
In a recent campaign to reduce the rapidly increasing volume of water produced from Minagish Oolite reservoir, a large number of workovers were carried out based on the current understanding of the vertical barriers / baffles, resulting in bringing down the water-cut level appreciably. The paper analyzes the results obtained from carrying out the numerous workovers for water shut-off in the recent campaign. This analysis has been utilized in an attempt to improve the history match in the dynamic reservoir simulation, especially the water-cut history match. Whereas good match of long water-cut history before the recent water shut-off jobs indicates absence of serious issue of well integrity, transmissibility modifiers in the simulation model were required, in order to improve water-cut history match in the post water shut-off period. Thus, there is vast improvement in the simulation team's understanding of the lateral distribution and strength of barriers / baffles. This has greatly aided in the formulation of more pragmatic plans for future workovers involving water shut-off by squeezing-off or isolating watered out layers. The result is a more robust prediction of production profile from the future field development activities.
The paper presents how the integrated approach of the open-hole, cased hole logs data with field performance in the history match process of simulation helps in the improvement of reservoir simulation modeling.
The compositional flow simulation model was frequently used to evaluate the miscible water alternating CO2 flooding (CO2-WAG). The uncertainty and sensitivity analysis have to be conducted to examine the parameters mostly affecting the performance of the process. Accordingly, multiple simulation runs require to be constructed which is a time-consuming procedure and finally increase the computational cost. This paper presents a simplistic approach to assess the miscible CO2-WAG flooding in an Iraqi oilfield through developing a statistical proxy model. The Central Composite Design (CCD) was employed to build the proxy model to determine the incremental oil recovery (ΔFOE) as a function of seven reservoir and operating parameters (permeability, porosity, ratio of vertical to horizontal permeability, cyclic length, bottom hole pressure, ratio of CO2 slug size to water slug size, and CO2 slug size). In total, 81 compositional simulation runs were conducted at field-scale to establish the proxy model. The validity of the model was investigated based on statistical tools; the Root Mean Squared Error (RMSE), R-squared statistic and the adjusted R-squared statistic of 0.0095, 0.9723 and 0.9507 confirmed the reliability of the model. The most influential and the optimum values of the parameters that lead to the higher ΔFOE during miscible CO2-WAG process were identified through proxy modeling analysis. The developed model was created based on the Nahr Umr reservoir in Subba oilfield and can be applied to roughly estimate the ΔFOE during the miscible CO2-WAG process at the same geological conditions as Nahr Umr reservoir.
Alkandari, Dana K. (Australian College of Kuwait) | AlTheferi, Ghaneima M. (Australian College of Kuwait) | Almutawaa, Hawra'a M. (Australian College of Kuwait) | Almutairi, Maryam (Australian College of Kuwait) | Alhindi, Nora (Australian College of Kuwait) | Al-Rashid, Sherifa M. (Australian College of Kuwait) | Al-Bazzaz, Waleed H. A. (Kuwait Institute For Scientific Research)
Formation damage is the impairment of permeability of rocks inside a petroleum reservoir. This occurs during drilling, production, stimulation and enhanced oil recovery operations, by various mechanisms such as chemical, mechanical, biological and thermal. Near wellbore formation damages have a great impact on productivity of the damaged formation. Acidizing is a stimulation method to remove the effect of near wellbore damage through reacting with damaging materials or the formation rocks (carbonate or sandstone rocks) to restore or improve permeability around the wellbore. Several experiments are conducted to study the effect of temperature and acid concentration combined on the efficiency of matrix acidizing. Three different concentrations scenarios of hydrochloric acid (3%, 15%, and 28%) and 4 different temperatures scenarios (25 °C, 35 °C, 70 °C, and 100 °C) were tested to investigate pore-enlargement success effect on permeability. The purpose of this experiment is to introduce the concept of optimized temperature augmented with optimized acid concentration in carbonate matrix acidulation. Morphology of pore geometry and area measurement software is used. New Advancement in imaging that captured pore area enlargement as big-data necessarily for artificial intelligence modeling. Captured pores before treatment and captured pores after thermal-HCL acid treatment have demonstrated that image processing of the actual acidized rock data can select the optimized recipe concentration of acid that will increase permeability, hence recovery. The results show that matrix acidizing is an effective method to improve permeability and enhance production, as it demonstrates that using less acid concentration with the optimized temperature can result in a favorable and satisfying outcomes.
Eldabbour, Mohamed (Abu Qir Petroleum) | Fadel, Ayman (Abu Qir Petroleum) | Soliman, Ali (Abu Qir Petroleum) | Safwat, Hatem (Abu Qir Petroleum) | Labib, Amr (Abu Qir Petroleum) | Belli, Andrea (Abu Qir Petroleum) | McLaughlin, Ryan (Corex U.K. Ltd) | Patey, Ian T.M. (Corex U.K. Ltd) | Munro, Murdo S. (Corex U.K. Ltd) | Jones, David (Corex U.K. Ltd)
Gravel pack completion operations are a sand production management technique that is considered successful if the well produces no sand and has minimal impact upon the potential productivity and hydrocarbon recovery. However, statistics show that many gravel packed wells suffer reduced productivity as a result of damaging mechanisms induced by gravel pack operations and completion fluids. This provides an opportunity for improved hydrocarbon recovery if the mechanisms are understood.
A study was conducted to simulate the alterations caused by the gravel pack operations including gravel carrier fluid, completion fluid and lost circulation material. Simulations using reservoir core samples were carried out at near-wellbore conditions, in order to examine operational fluid interactions with the reservoir and assess the impact of a stimulation fluid. Cores from a range of rock types were selected, and prepared to initial gas-leg saturation. An operational sequence consisting of completion fluid, gas production, stimulation fluid, completion fluid, and production of gas was carried out, with permeability measurements before and after the sequence.
In all core samples, the introduction of the completion fluid during gravel pack installation resulted in alterations of 30-60% reduction in core permeability. Geological interpretative analysis showed damage mechanisms including clay fines movement and pore blockage, dissolution of native cement, and retention of operational fluid in the pores. It was believed that retention of fluids was having the most significant impact upon permeability. Stimulations were carried out for all samples to quantify the effect of acid on removing the formation damage resulting from the gravel pack operations. The experiments showed 5-10% improvement on average except for one core sample, which showed 40% improvement.
Based upon the previous results, a modified sequence was examined, utilizing an alternative stimulation fluid/acid sequence and adding an extra operational stage. The experiments showed that after treatment an improvement of around 10% was noted, and after an additional stage, a further 8% improvement was seen. The final permeability was over 80-90% of the initial permeability, indicating that there was the potential for good productivity and recovery of hydrocarbons.
The results of the study were applied to seven gravel pack jobs in three wells and the field results showed the reduction in productivity after gravel pack installation was around only 10%, compared to previous wells which showed more than 50% reduction in productivity.
Quintero, Harvey (ChemTerra Innovation) | Abedini, Ali (Interface Fluidics Limited) | Mattucci, Mike (ChemTerra Innovation) | O’Neil, Bill (ChemTerra Innovation) | Wust, Raphael (AGAT Laboratories) | Hawkes, Robert (Trican Well Service LTD) | De Hass, Thomas (Interface Fluidics Limited) | Toor, Am (Interface Fluidics Limited)
For optimizing and enhancing hydrocarbon recovery from unconventional plays, the technological race is currently focused on development and production of state-of-the-art surfactants that reduce interfacial tension to mitigate obstructive capillary forces and thus increase the relative permeability to hydrocarbon (
A heterogeneous dual-porosity dual-permeability microfluidic chip was designed and developed with pore geometries representing shale formations. This micro-chip simulated Wolfcamp shale with two distinct regions: (i) a high-permeability fracture zone (20 µm pore size) interconnected to (ii) a low-permeability nano-network zone (100 nm size). The fluorescent microscopy technique was applied to visualize and quantify the performance of different flowback enhancers during injection and flowback processes.
This study highlights results from the nanofluidic analysis performed on Wolfcamp Formation rock specimens using a microreservoir-on-a-chip, which showed the benefits of the multi-functionalized surfactant (MFS) in terms of enhancing oil/condensate production. Test results obtained at a simulated reservoir temperature of 113°F (45°C) and a testing pressure of 2,176 psi (15 MPa) showed a significant improvement in relative permeability to hydrocarbon (
Measurements using a high-resolution spinning drop tensiometer showed a 40-fold reduction in interfacial tension when the stimulation fluid containing MFS was tested against Wolfcamp crude at 113°F (45°C). Also, MFS outperformed other premium surfactants in Amott spontaneous imbibition analysis when tested with Wolfcamp core samples.
This work used a nanofluidic model that appropriately reflected the inherent nanoconfinement of shale/tight formation to resolve the flowback process in hydraulic fracturing, and it is the first of its kind to visualize the mechanism behind this process at nanoscale. This platform also demonstrated a cost-effective alternative to coreflood testing for evaluating the effect of chemical additives on the flowback process. Conventional lab and field data were correlated with the nanofluidic analysis.
Xu, Wei (CNOOC Research Institute Co., Ltd.) | Chen, Kaiyuan (Beijing Key Laboratory of Unconventional Natural Gas Geological Evalution and Development Engineeing, China University of Geosciences Beijing) | Fang, Lei (Beijing Key Laboratory of Unconventional Natural Gas Geological Evalution and Development Engineeing, China University of Geosciences Beijing) | Zhang, Yingchun (CNOOC Research Institute Co., Ltd.) | Jing, Zhiyi (CNOOC Research Institute Co., Ltd.) | Liu, Jun (CNOOC Research Institute Co., Ltd.) | Zou, Jingyun (CNOOC Research Institute Co., Ltd.)
The lacustrine delta sandbody deposited in the north of Albert Basin is unconsolidated due to the shallow burial depth, which leads to an ultra-high permeability (up to 20 D) with large variation and poor diagenesis. Log derived permeability differs greatly with DST results. Thus, permeability simulation is challenging in 3D geomodeling. A hierarchical geomodeling approach is presented to bridge the gap among the ultra-high permeability log, model and DST results. The ultimate permeability model successfully matched the logging data and DST results into the geological model.
Based on the study of sedimentary microfacies, the new method identifies different discrete rocktypes (DRT) according to the analyis of core, thin section and conventional and special core analysis (e.g., capillary pressure). In this procedure, pore throat radius, flow zone index (FZI) and other parameters are taken into account to identify the DRT. Then, hierarchical modeling approach is utilized in the geomodeling. Firstly, the sedimentary microfacies model is established within the stratigraphic framework. Secondly, the spatial distribution model of DRT is established under the control of sedimentary microfacies. Thirdly, the permeability distribution is simulated according to the different pore-permeability relation functions derived from each DRT. Finally, the permeability model is compared with the logging and testing results.
Winland equation was improved based on the capillary pressure (Pc) data of special core analysis. It is found that the highest correlation between pore throat radius and reservoir properties was reached when mercury injection was 35%. The corresponding formula of R35 is selected to calculate the radius of reservoir pore throat. Reservoirs are divided into four discrete rock types according to parameters such as pore throat radius and flow zone index. Each rock type has its respective lithology, thin section feature and pore-permeability relationship. The ultra-high permeability obtained by DST test reaches up to 20 D, which belongs to the first class (DRT1) quality reservoir. It is located in the center of the delta channel with high degree of sorting and roundness. DRT4 is mainly located in the bank of the channels. It has a much higher shale content and the permeability is generally less than 50 mD. Through three-dimensional geological model, sedimentary facies, rock types and pore-permeability model are coupled hierarchically. Different pore-permeability relationships are given to different DRTs. After reconstructing the permeability model, the simulation results are highly matched with the log and DST test results.
This hierarchical geomodeling approach can effectively solve the simulation problem in the ultra-high permeability reservoir. It realizes a quantitative characterization for the complex reservoir heterogeneity. The method presented can be applied to clastic reservoir. It also plays a significant positive role in carbonate reservoir characterization.
Faster production declines than initially forecast were observed in numerous deep-water assets. These wells were completed as Cased Hole Frac-Pack (CHFP) completions (
Seven key damage mechanisms were identified as forming the basis for PI degradation: 1) off-plane perforation stability, 2) fines migration, 3) fracture conductivity, 4) fracture connectivity, 5) fluid invasion, 6) non-Darcy flow and 7) creep effects. A near wellbore production model incorporating the completion, fracture geometry and reservoir is coupled with a geomechanics model to assess each mechanism. A Design of Experiment setup varies the input ranges associated with each of the seven damage mechanisms. Input parameters for the model are risked and rely on ranges from standard and newly developed well and lab tests. The model assesses well performance and driving mechanisms at different points in time within the production life.
Primarily the study focused on high permeability and highly over pressured reservoirs. For the types of wells/fields assessed in the study, the results indicated three phases of decline based on the interaction between the formation properties, the completion components and the operating parameters. The three phases breakdown into: (1) a pre-rock failure stage where declines are relatively small, (2) an ongoing rock failure stage where declines are rapid and (3) a post failure stage where declines are again moderate. In each of these stages different parameters and damage mechanisms were assessed to be impactful. The workflow was also utilized to match pre and post acidizing treatments. A comparison for varying rock types was included looking at the impact of rock strength and formation permeability on the ranking of the damage mechanisms. The impact of operating parameters such as drawdown can also be assessed with the tool showing that increased drawdowns may not always be beneficial to the long-term production of the well.
The paper presents the underlying drivers for PI Decline for deep-water assets of a specific attribute set. Through accurate representation of reservoir and completion, the workflow highlights the impact and combined impact of different damage mechanisms. The paper also shows a direct link between the mechanical properties (moduli and strength) and boundary conditions (pore pressure and stress) and the well performance and productivity. The workflow provides a methodology by which lab and field tests can be transformed into assessments of future well performance without strictly relying on analogs that may or may not be appropriate.
Reservoir depletion can induce substantial changes in the stress state of the rock. The coupled interaction between the pore fluid pressure and rock stress will then alter the reservoir permeability, which in turn reversely affects the productivity index of the production well. A new nonlinear analytical solution is developed for the drawdown-dependent productivity index of reservoirs under steady-state flow. Biot's theory of poroelasticity is used to derive the depletion-induced changes in the reservoir rock porosity and permeability. The well-known Mindlin's solution for a Nucleus of Strain in a semi-infinite elastic medium is applied as Green's function and integrated over the depleted volume of reservoir rock to obtain the 3D distribution of stress and volumetric strain distributions. The fluid transport equation is nonlinearly coupled to the solid mechanics solution via the stress-dependent permeability coefficients. A perturbation technique is applied to mathematically treat the described nonlinearity to solve for the coupled equations of pore fluid flow and rock stress under steady-state flow. The good match between the obtained analytical approximations for productivity index and the numerical solutions verifies the correctness and robustness of the proposed model.
Results indicate and confirm the expected strong dependency of the well productivity index to the drawdown magnitude as well as the poroelastic constitutive parameters of the reservoir rock, with the highest sensitivity to drained bulk modulus, followed by the reservoir depth and solid-grain modulus. The lowest PI sensitivity is to the pore fluid modulus and Poisson's ratio. The resulting productivity index is found out to be drawdown-dependent, which can render values substantially different than the productivity index estimate from the conventional flow-only analysis. The presented estimates for the related nonlinear productivity index can be readily used by the practicing engineers.