Pressure Transient Behavior for Alternating Polymer Flooding in a Three-zone Composite Reservoir

2017 ◽  
Vol 25 (1) ◽  
pp. 1-10 ◽  
Author(s):  
Changyu Zhu ◽  
Shiqing Cheng ◽  
Youwei He ◽  
Engao Tang ◽  
Xiaodong Kang ◽  
...  
Keyword(s):  
History Matching ◽  
Petroleum Industry ◽  
Composite Model ◽  
Polymer Flooding ◽  
Analysis Model ◽  
High Concentration ◽  
Pressure Derivative ◽  
Type Curves ◽  
Formation Evaluation ◽  
Pressure Analysis

Alternating polymer flooding has achieved great attractions recently in oil industry, however, the research of pressure analysis in alternating polymer flooding reservoir is rare. This work presents a numerical pressure analysis method of three-zone composite model for formation evaluation. A new numerical pressure analysis model (three-zone composite model) is established by considering diffusion, convection, shear, and inaccessible pore volume, which is based on the rheology experiments. Based on this model, the type curves are then developed and sensitivity analysis is further conducted. The type curves have seven regimes in three-zone composite model. The characteristic is the obvious upturn of pressure derivative curve in transient regime between low concentration and high concentration polymer solution. Formation parameters can be interpreted by history matching and formation evaluation can be conducted based on this model. As an important part of formation evaluation, formation damage as a result of adsorption of polymers in porous media is evaluated by comparing the interpreted permeability with the original value before polymer flooding. The field test data proves that this proposed method can accurately evaluate reservoir characteristics in alternating polymer flooding reservoirs, which emphasizes the potential application of this method in petroleum industry.

scholarly journals Investigation on Interference Test for Wells Connected by a Large Fracture

2019 ◽  
Vol 9 (1) ◽  
pp. 206
Author(s):  
Guofeng Han ◽  
Yuewu Liu ◽  
Wenchao Liu ◽  
Dapeng Gao
Keyword(s):  
Double Porosity ◽  
Flow In Porous Media ◽  
Connection Form ◽  
Analysis Model ◽  
Pressure Derivative ◽  
Type Curve ◽  
Type Curves ◽  
Multi Stage ◽  
Interference Test ◽  
Straight Lines

Pressure communication between adjacent wells is frequently encountered in multi-stage hydraulic fractured shale gas reservoirs. An interference test is one of the most popular methods for testing the connectivity of a reservoir. Currently, there is no practical analysis model of an interference test for wells connected by large fractures. A one-dimensional equation of flow in porous media is established, and an analytical solution under the constant production rate is obtained using a similarity transformation. Based on this solution, the extremum equation of the interference test for wells connected by a large fracture is derived. The type-curve of pressure and the pressure derivative of an interference test of wells connected by a large fracture are plotted, and verified against interference test data. The extremum equation of wells connected by a large fracture differs from that for homogeneous reservoirs by a factor 2. Considering the difference of the flowing distance, it can be concluded that the pressure conductivity coefficient computed by the extremum equation of homogeneous reservoirs is accurate in the order of magnitude. On the double logarithmic type-curve, as time increases, the curves of pressure and the pressure derivative tend to be parallel straight lines with a slope of 0.5. When the crossflow of the reservoir matrix to the large fracture cannot be ignored, the slope of the parallel straight lines is 0.25. They are different from the type-curves of homogeneous and double porosity reservoirs. Therefore, the pressure derivative curve is proposed to diagnose the connection form of wells.

scholarly journals Response surface methodology approach for the optimisation of adsorption of hydrolysed polyacrylamide from polymer-flooding wastewater onto steel slag: a good option of waste mitigation

2017 ◽  
Vol 76 (4) ◽  
pp. 776-784 ◽  
Author(s):  
Mijia Zhu ◽  
Jun Yao ◽  
Zhonghai Qin ◽  
Luning Lian ◽  
Chi Zhang
Keyword(s):  
Response Surface Methodology ◽  
Response Surface ◽  
Removal Efficiency ◽  
Contact Time ◽  
Interactive Effect ◽  
Steel Slag ◽  
Oxygen Demand ◽  
Polymer Flooding ◽  
High Concentration ◽  
Adsorbent Dosage

Wastewater produced from polymer flooding in oil production features high viscosity and chemical oxygen demand because of the residue of high-concentration polymer hydrolysed polyacrylamide (HPAM). In this study, steel slag, a waste from steel manufacturing, was studied as a low-cost adsorbent for HPAM in wastewater. Optimisation of HPAM adsorption by steel slag was performed with a central composite design under response surface methodology (RSM). Results showed that the maximum removal efficiency of 89.31% was obtained at an adsorbent dosage of 105.2 g/L, contact time of 95.4 min and pH of 5.6. These data were strongly correlated with the experimental values of the RSM model. Single and interactive effect analysis showed that HPAM removal efficiency increased with increasing adsorbent dosage and contact time. Efficiency increased when pH was increased from 2.6 to 5.6 and subsequently decreased from 5.6 to 9.3. It was observed that removal efficiency significantly increased (from 0% to 86.1%) at the initial stage (from 0 min to 60 min) and increased gradually after 60 min with an adsorbent dosage of 105.2 g/L, pH of 5.6. The adsorption kinetics was well correlated with the pseudo-second-order equation. Removal of HPAM from the studied water samples indicated that steel slag can be utilised for the pre-treatment of polymer-flooding wastewater.

Caveats and Pitfalls of Production Forecast Uncertainty Analysis Using Design of Experiments

2021 ◽  
Author(s):  
Boxiao Li ◽  
Hemant Phale ◽  
Yanfen Zhang ◽  
Timothy Tokar ◽  
Xian-Huan Wen
Keyword(s):  
Design Of Experiments ◽  
Uncertainty Analysis ◽  
History Matching ◽  
Petroleum Industry ◽  
Production Forecast ◽  
Forecast Uncertainty ◽  
Field Development ◽  
Development Alternatives ◽  
Modeling Principles ◽  
Made In

Abstract Design of Experiments (DoE) is one of the most commonly employed techniques in the petroleum industry for Assisted History Matching (AHM) and uncertainty analysis of reservoir production forecasts. Although conceptually straightforward, DoE is often misused by practitioners because many of its statistical and modeling principles are not carefully followed. Our earlier paper (Li et al. 2019) detailed the best practices in DoE-based AHM for brownfields. However, to our best knowledge, there is a lack of studies that summarize the common caveats and pitfalls in DoE-based production forecast uncertainty analysis for greenfields and history-matched brownfields. Our objective here is to summarize these caveats and pitfalls to help practitioners apply the correct principles for DoE-based production forecast uncertainty analysis. Over 60 common pitfalls in all stages of a DoE workflow are summarized. Special attention is paid to the following critical project transitions: (1) the transition from static earth modeling to dynamic reservoir simulation; (2) from AHM to production forecast; and (3) from analyzing subsurface uncertainties to analyzing field-development alternatives. Most pitfalls can be avoided by consistently following the statistical and modeling principles. Some pitfalls, however, can trap experienced engineers. For example, mistakes made in handling the three abovementioned transitions can yield strongly unreliable proxy and sensitivity analysis. For the representative examples we study, they can lead to having a proxy R2 of less than 0.2 versus larger than 0.9 if done correctly. Two improved experimental designs are created to resolve this challenge. Besides the technical pitfalls that are avoidable via robust statistical workflows, we also highlight the often more severe non-technical pitfalls that cannot be evaluated by measures like R2. Thoughts are shared on how they can be avoided, especially during project framing and the three critical transition scenarios.

scholarly journals Integrated Halo Model And Hydrodynamic Simulation For Optimization Oil Production In Crystalline Fractured Reservoirs

2021 ◽  
Author(s):  
Hung Vo Thanh ◽  
Kang-Kun Lee
Keyword(s):  
Oil Recovery ◽  
History Matching ◽  
Fractured Reservoirs ◽  
Petroleum Industry ◽  
Oil Production ◽  
Modelling And Simulation ◽  
Development Plan ◽  
Sweep Efficiency ◽  
Field Development ◽  
The World

Abstract Basement formation is known as the unique reservoir in the world. The fractured basement reservoir was contributed a large amount of oil and gas for Vietnam petroleum industry. However, the geological modelling and optimization of oil production is still a challenge for fractured basement reservoirs. Thus, this study aims to introduce the efficient workflow construction reservoir models for proposing the field development plan in a fractured crystalline reservoir. First, the Halo method was adapted for building the petrophysical model. Then, Drill stem history matching is conducted for adjusting the simulation results and pressure measurement. Next, the history-matched models are used to conduct the simulation scenarios to predict future reservoir performance. The possible potential design has four producers and three injectors in the fracture reservoir system. The field prediction results indicate that this scenario increases approximately 8 % oil recovery factor compared to the natural depletion production. This finding suggests that a suitable field development plan is necessary to improve sweep efficiency in the fractured oil formation. The critical contribution of this research is the proposed modelling and simulation with less data for the field development plan in fractured crystalline reservoir. This research's modelling and simulation findings provide a new solution for optimizing oil production that can be applied in Vietnam and other reservoirs in the world.

scholarly journals The Effect of Rheology of Viscoelastic Polymer on Pressure Transient Response in Near-Wellbore Regions

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-12
Author(s):  
Jia Zhang ◽  
Shiqing Cheng ◽  
Jie Zhan ◽  
Qi Han
Keyword(s):  
Shear Thickening ◽  
Shear Thinning ◽  
Polymer Flooding ◽  
High Shear ◽  
Pressure Data ◽  
Transient Pressure ◽  
Pressure Derivative ◽  
Shear Rates ◽  
Viscoelastic Polymer ◽  
Thickening Behavior

Viscoelastic polymer solution shows shear thinning behavior at low shear rates and shear thickening behavior at high shear rates in reservoirs. However, models that ignored shear thickening behavior were commonly employed to interpret transient pressure data derived from tested wells in viscoelastic polymer flooding systems; although, viscoelastic polymer solutions show shear thickening behavior in the near-wellbore region due to high shear rate. To better characterize the oilfield with pressure transient analysis in viscoelastic polymer flooding systems, we developed a numerical model that takes into account both shear thinning behavior and shear thickening behavior. A finite volume method was employed to discretize partially differential flow equations in a hybrid grid system including PEBI mesh and Cartesian grid, and the Newton-Raphson method was used to solve the fully implicit nonlinear system. To illustrate the significance of our model, we compared our model with a model that ignores the shear thickening behavior by graphing their solutions on log-log plots. In the flow regime of near-wellbore damage, the pressure derivative computed by our model is distinctly larger than that computed by the model ignoring shear thickening behavior. Furthermore, the effect of shear thickening behavior on pressure derivative differs from that of near-wellbore damage. We then investigated the influence of shear thickening behavior on pressure derivative with different polymer injection rates, injection rates, and permeabilities. The results can provide a benchmark to better estimate near-wellbore damage in viscoelastic polymer flooding systems. Besides, we demonstrated the applicability and accuracy of our model by interpreting transient pressure data from a field case in an oilfield with viscoelastic polymer flooding treatments.

scholarly journals Experimental Investigation of Chemical Flooding Using Nanoparticles and Polymer on Displacement of Crude Oil for Enhanced Oil Recovery

2020 ◽  
Vol 2020 ◽  
pp. 1-10
Author(s):  
Imran Akbar ◽  
Hongtao Zhou ◽  
Wei Liu ◽  
Muhammad Usman Tahir ◽  
Asadullah Memon ◽  
...  
Keyword(s):  
Fluid Flow ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Petroleum Industry ◽  
Chemical Flooding ◽  
Polymer Gel ◽  
Core Flooding ◽  
High Concentration ◽  
Remaining Oil ◽  
Water Cut

In the petroleum industry, the researchers have developed a new technique called enhanced oil recovery to recover the remaining oil in reservoirs. Some reservoirs are very complex and require advanced enhanced oil recovery (EOR) techniques containing new materials and additives in order to produce maximum oil in economic and environmental friendly manners. In this work, the effects of nanosuspensions (KY-200) and polymer gel HPAM (854) on oil recovery and water cut were studied in the view of EOR techniques and their results were compared. The mechanism of nanosuspensions transportation through the sand pack was also discussed. The adopted methodology involved the preparation of gel, viscosity test, and core flooding experiments. The optimum concentration of nanosuspensions after viscosity tests was used for displacement experiments and 3 wt % concentration of nanosuspensions amplified the oil recovery. In addition, high concentration leads to more agglomeration; thus, high core plugging takes place and diverts the fluid flow towards unswept zones to push more oil to produce and decrease the water cut. Experimental results indicate that nanosuspensions have the ability to plug the thief zones of water channeling and can divert the fluid flow towards unswept zones to recover the remaining oil from the reservoir excessively rather than the normal polymer gel flooding. The injection pressure was observed higher during nanosuspension injection than polymer gel injection. The oil recovery was achieved by about 41.04% from nanosuspensions, that is, 14.09% higher than polymer gel. Further investigations are required in the field of nanoparticles applications in enhanced oil recovery to meet the world's energy demands.

Visco-Elastic Property Studies on Polymer Flooding Systems with High Concentrations

2012 ◽  
Vol 550-553 ◽  
pp. 834-837
Author(s):  
Ji Gang Wang ◽  
Quan Qing Du ◽  
Peng Wu ◽  
Shao Li Hu ◽  
Pan Niu
Keyword(s):  
Elastic Property ◽  
Oil Recovery ◽  
Elastic Characteristic ◽  
Polymer Flooding ◽  
Oil Field ◽  
High Concentration ◽  
Improved Oil Recovery ◽  
High Molecular Weight Polymer ◽  
Molecular Weight Polymer ◽  
Asp Flooding

Keywords: Visco-elastic property; polymer flooding; oil recovery Abstract. Polymer flooding and ASP flooding has improved oil recovery a lot in Daqing oil field. In ASP flooding, the existence of alkali decreases the visco-elastic characteristic of polymer, which decreases the oil recovery of polymer flooding. The aim of this paper was to study the visco-elastic characteristic, shear resistance in high concentration and high molecular weight polymer flooding, and analyzed the suitable parameter of it .They can provide the theory of polymer flooding development and application research.

scholarly journals Hybrid Engineered Water–Polymer Flooding in Carbonates: A Review of Mechanisms and Case Studies

2020 ◽  
Vol 10 (17) ◽  
pp. 6087
Author(s):  
Mariam Shakeel ◽  
Peyman Pourafshary ◽  
Muhammad Rehan Hashmet
Keyword(s):  
Oil Recovery ◽  
Petroleum Industry ◽  
Cost Effective ◽  
Polymer Flooding ◽  
Driving Factors ◽  
Water Flooding ◽  
Wettability Alteration ◽  
Rock Surface ◽  
Hybrid Technique ◽  
High Salinity Water

The fast depletion of oil reserves has steered the petroleum industry towards developing novel and cost-effective enhanced oil recovery (EOR) techniques in order to get the most out of reservoirs. Engineered water–polymer flooding (EWPF) is an emerging hybrid EOR technology that uses the synergetic effects of engineered water (EW) and polymers to enhance both the microscopic and macroscopic sweep efficiencies, which mainly results from: (1) the low-salinity effect and the presence of active ions in EW, which help in detachment of carboxylic oil material from the rock surface, wettability alteration, and reduction in the residual oil saturation; (2) the favorable mobility ratio resulting from the use of a polymer; and (3) the improved thermal and salinity resistance of polymers in EW. Various underlying mechanisms have been proposed in the literature for EW EOR effects in carbonates, but the main driving factors still need to be understood properly. Both polymer flooding (PF) and EW have associated merits and demerits. However, the demerits of each can be overcome by combining the two methods, known as hybrid EWPF. This hybrid technique has been experimentally investigated for both sandstone and carbonate reservoirs by various researchers. Most of the studies have shown the synergistic benefits of the hybrid method in terms of two- to four-fold decreases in the polymer adsorption, leading to 30–50% reductions in polymer consumption, making the project economically viable for carbonates. EWPF has resulted in 20–30% extra oil recovery in various carbonate coreflood experiments compared to high-salinity water flooding. This review presents insights into the use of hybrid EWPF for carbonates, the main recovery driving factors in the hybrid process, the advantages and limitations of this method, and some areas requiring further work.

Pressure-Derivative Type Curves, for Vertically Fractured Wells

1988 ◽  
Vol 3 (01) ◽  
pp. 156-158 ◽  
Author(s):  
Djebbar Tiab ◽  
Suresh K. Puthigai
Keyword(s):  
Pressure Derivative ◽  
Type Curves ◽  
Derivative Type
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