Falloff Tests Research Articles

Maximizing efficiency and uniformity in SAGD steam circulation through effect of heat convection

The thermal recovery is facing the challenge of improving quality and efficiency. Steam-assisted gravity drainage (SAGD) steam circulation has a profound implications for the formal production. There is a lack of research on the situation when the steam injection pressure of injection well is lower than that of production well during startup stage. In this paper, the effects of diverse injection pressure difference on SAGD steam circulation and production stage are investigated by analytical modeling and numerical simulation, especially when the steam injection pressure of producer well is larger than that of injection well, and reliable results are obtained by temperature falloff test and model comparison validation. Meanwhile, in order to minimize the factors affecting the simulation accuracy, a sensitivity analysis of the temperature prediction model for the startup stage is carried out using Monte Carlo method and the finest possible mesh is used in the numerical simulation. The results show that:①The preheating results are faster and more uniform than the conventional preheating method when steam injection pressure of producer is greater than that of injector, and the subsequent production indexes are also superior to those of the conventional preheating method. ②The injected steam temperature had the greatest effect on the prediction accuracy of the analytical model; The finer the numerical simulation grid division, the lower the midpoint temperature of the horizontal well pair; ③An optimal range of injection pressure differences that achieves the best balance between preheating efficiency and thermal recovery effectiveness is achieved with Pprod-Pinj in the range of 400–500 kPa. ④The preheating method investigated in this paper minimizes the effect by unfavorable factors such as reservoir non-homogeneity, which holds the potential for more uniform, time-saving preheating and without the addition of field equipment.

Evaluation of near wellbore damaged conditions with an injection - falloff tests during transient flow regime in clastic hydrocarbon reservoir

Low or near zero daily oil production from a well below its potential is undesirable and should be addressed. This problem is caused by permeability reduction or impairments in the vicinity of a wellbore and could be due to one or combinations of the following factors; mud filtrate invasion, fines redeposition due to production, microbial growth, fracturing fluid, and enhanced chemical processes. The extent of this problem has to be quantitatively evaluated, using a skin factor, before an appropriate solution can be developed. A set of secondary data was simulated with a commercial software package, for a reservoir undergoing transient flow condition acting infinitely. A water injection well, fully perforated, is placed at the centre of an infinite-acting reservoir, for constant water injection. The wellbore radius of 0.5 ft fully penetrated the entire length of 190 ft, and injected water at 250 bbls per day, with water viscosities of 0.8 cP to 1.2 cP, continuously for 4 days. Water injection pressure stabilized at 1300 psi. Analysis of both injectivity and falloff were performed with an initial assumption of zero wellbore storage effects to evaluate formation permeability and skin factor, S. The result showed that skin factor increases with decreasing water viscosities. At water viscosity of 0.8 cP to 1.2 cP, a constant value of skin factor was obtained. An S value of +0.09 indicated that the near wellbore environment is slightly damaged. Therefore, it requires light acidization.

Transient Pressure Behavior of CBM Wells during the Injection Fall-Off Test Considering the Quadratic Pressure Gradient.

Conventional coalbed methane (CBM) reservoir models for injection fall-off testing often disregard the quadratic pressure gradient's impact. This omission leads to discrepancies in simulating the transient behavior of formation fluids and extracting critical reservoir properties. Accurate determination of permeability, storability, and other properties is crucial for effective reservoir characterization and production forecasting. Inaccurate estimations can lead to suboptimal well placement, ineffective production strategies, and ultimately, missed economic opportunities. To address this shortcoming, we present a novel analytical model that explicitly incorporates the complexities of the quadratic pressure gradient and dual-permeability flow mechanisms, prevalent in many CBM formations where nanopores are rich, presenting a kind of natural nanomaterial. This model offers significant advantages over traditional approaches. By leveraging variable substitution, it facilitates the derivation of analytical solutions in the Laplace domain, subsequently converted to real-space solutions for practical application. These solutions empower reservoir engineers to generate novel type curves, a valuable tool for analyzing wellbore pressure responses during injection fall-off tests. By identifying distinct flow regimes within the reservoir based on these type curves, engineers gain valuable insights into the dynamic behavior of formation fluids. This model goes beyond traditional approaches by investigating the influence of the quadratic pressure gradient coefficient, inter-porosity flow coefficient, and storability ratio on the pressure response. A quantitative comparison with traditional models further elucidates the key discrepancies caused by neglecting the quadratic pressure gradient. The results demonstrate the proposed model's ability to accurately depict the non-linear flow behavior observed in CBM wells. This translates to more reliable pressure and pressure derivative curves that account for the impact of the quadratic pressure gradient.

In situ coal permeability and favorable development methods for coalbed methane (CBM) extraction in China: From real data

Permeability plays a significant role in the economic viability of coalbed methane (CBM) development. In China, in situ permeability obtained from injection fall-off tests range from 0.0001 to 41 mD at depths of 130–1728 m, with the majority (78%) falling between 0.01 and 1 mD. Coal reservoirs with high rank, common cleat mineralization, and depth-dependent high stress may result in extremely low permeability. Low-rank coal and cataclastic coal exhibit more favorable permeability conditions at shallow depths. Heterogeneity in coal rank, coal texture, and stress magnitude results in a discrete distribution of permeability both regionally and vertically. Most deep seams are highly compressed with extremely low permeability (<0.1 mD) as high stress levels. Multilateral horizontal wells work best with high permeability seams, while vertical wells with conventional hydraulic fracturing demonstrate limited adaptability to deep and low-permeability seams due to insufficient proppant-supported fractures. With increasing depth, both vertical and horizontal wells should employ larger fracturing scales to create effectively supported zones with higher fracture conductivity and reduced stress sensitivity to enhance CBM productivity. Horizontal wells with large-scale volume fracturing demonstrate superior performance compared to vertical wells in extracting CBM from deep, low-permeability, and high gas saturation reservoirs.

Assessment of World’s First Two Polymer Injectivity Tests Performed in Two Giant High-Temperature/High-Salinity Carbonate Reservoirs Using Single-Well Simulation Models and Pressure Falloff Tests Analysis

Summary Polymer flooding is a mature enhanced oil recovery (EOR) technology that has been widely implemented around the world for more than 60 years. Polymer flooding mostly targets medium- to high-permeability sandstone reservoirs with moderate salinity, hardness, and temperatures. However, in the last few years, the envelope of polymer flooding has been expanded to harsher reservoir conditions of high-temperature and high-salinity mixed-wet to oil-wet heterogeneous carbonate reservoirs. Development of novel polymers and innovative field application concepts has allowed for the reconsideration of polymer-based EOR as a promising technology to improve sweep efficiency for these challenging reservoirs. Polymer injectivity is one of the key challenges for polymer flooding projects and requires a rigorous derisking program that includes laboratory and field testing. A comprehensive laboratory program was designed to assess and investigate polymer thermal stability, polymer rheology in porous media, adsorption, and injectivity using reservoir core samples. In addition, two polymer injectivity tests (PITs) were performed in two giant light oil (0.3 cp) carbonate reservoirs in onshore Abu Dhabi under harsh conditions of high salinity (&amp;gt;200 g/L), high divalent ions (&amp;gt;20 g/L), high temperature (&amp;gt;250°F), and H2S concentration of up to 40 ppm. The polymer used during the two PITs (PIT 1 2019 and PIT 2 2021) is a new generation of EOR polymer (SAV 10) with high 2-acrylamido-tertiary-butyl sulfonic acid content that was specifically developed to tolerate such harsh conditions. This paper is focused on the interpretation of the PITs and lessons learned for future polymer-based EOR projects. The detailed data acquired in both tests were used to evaluate the polymer injectivity at representative field conditions and in-depth mobility reduction. The PITs together with the extensive laboratory studies are part of a thorough derisking program for the upcoming world’s first innovative hybrid EOR multiwell pilots—simultaneous injection of miscible gas and polymer (SIMGAP) and simultaneous injection of water and polymer (SIWAP). Both PITs are composed of three stages that include a multirate waterflood baseline, polymer injection using different rates, and polymer concentrations followed by extended chase waterflooding. In addition, a sequence of multiple pressure falloff (PFO) tests was acquired during the PIT executions and analyzed to obtain the required uncertainty parameters for the history-matching exercise. Polymer preshearing was considered as part of both PIT programs with the aim to homogenize the polymer molecular weight distribution and reduce possible shear-thickening effects near the wellbore as per laboratory measurements. Two single-well 3D simulation models were built to incorporate the information from polymer laboratory studies and to interpret the large field data sets acquired during the PITs. Lessons learned from PIT 1 allowed us to optimize the PIT 2 design program and achieve better understanding of polymer characteristics. The interpretation of the pressure transient analysis (PTA) of the PFO tests and the 3D simulation models of the two PITs confirmed the generation of polymer banks and demonstrated effective propagation of the polymer into the reservoirs at target concentrations and representative rates of the future SIWAP and SIMGAP interwell pilots.

Pressure transient characteristics of non-uniform conductivity fractured wells in viscoelasticity polymer flooding based on oil–water two-phase flow

Polymer flooding in fractured wells has been extensively applied in oilfields to enhance oil recovery. In contrast to water, polymer solution exhibits non-Newtonian and nonlinear behavior such as effects of shear thinning and shear thickening, polymer convection, diffusion, adsorption retention, inaccessible pore volume and reduced effective permeability. Meanwhile, the flux density and fracture conductivity along the hydraulic fracture are generally non-uniform due to the effects of pressure distribution, formation damage, and proppant breakage. In this paper, we present an oil–water two-phase flow model that captures these complex non-Newtonian and nonlinear behavior, and non-uniform fracture characteristics in fractured polymer flooding. The hydraulic fracture is firstly divided into two parts: high-conductivity fracture near the wellbore and low-conductivity fracture in the far-wellbore section. A hybrid grid system, including perpendicular bisection (PEBI) and Cartesian grid, is applied to discrete the partial differential flow equations, and the local grid refinement method is applied in the near-wellbore region to accurately calculate the pressure distribution and shear rate of polymer solution. The combination of polymer behavior characterizations and numerical flow simulations are applied, resulting in the calculation for the distribution of water saturation, polymer concentration and reservoir pressure. Compared with the polymer flooding well with uniform fracture conductivity, this non-uniform fracture conductivity model exhibits the larger pressure difference, and the shorter bilinear flow period due to the decrease of fracture flow ability in the far-wellbore section. The field case of the fall-off test demonstrates that the proposed method characterizes fracture characteristics more accurately, and yields fracture half-lengths that better match engineering reality, enabling a quantitative segmented characterization of the near-wellbore section with high fracture conductivity and the far-wellbore section with low fracture conductivity. The novelty of this paper is the analysis of pressure performances caused by the fracture dynamics and polymer rheology, as well as an analysis method that derives formation and fracture parameters based on the pressure and its derivative curves.

In Situ Stress Distribution of Deep Coals and Its Influence on Coalbed Methane Development in the Shizhuang Block, Qinshui Basin, China.

The in situ stress plays a crucial role in variations in coal permeability, hydraulic fracturing behavior, and accordingly coalbed methane (CBM) productivity. As the depth increases, the effects of in situ stress will become more prominent. In the Shizhuang block, present-day stress magnitude and permeability of coals at depths >800 m were measured with multiple-cycle hydraulic fracturing and injection falloff test, respectively. The results show that most seams are under pressure reservoirs with pressure gradient <0.9 MPa/100 m. Horizontal stress magnitudes and gradients tend to increase (800-1200 m) and then decrease (>1200 m) with increasing depth. Strike-slip fault stress regimes are predominant, while seams with depth >1400 m are subjected to a normal fault stress regime. Coal permeability tends to decrease gradually with depth and tends to be convergence to 0.01 mD. Considering extremely low permeability of these deep seams, hydraulic fracturing must be applied to create seepage channels for gas and water drainage. Although the high horizontal stress difference in deep seams is favorable for the generation of longer and simple hydraulic fractures, there is no obvious relations between fracture length and gas productivity as poor-support fractures and limited sand migration distance. The current hydraulic fracturing missed the variable stress regimes and permeability at various depth, but used the similar fracturing schemes, leading to significant reduction in gas productivity with depth. Using the high viscosity fracturing fluid, great sand volume, big injection rate, and low sand concentration are recommended for hydraulic fracturing. Single-branch horizontal well with staged fracturing show better applicability for deep CBM extraction.

Pressure Transient Analysis for Water Injection Wells with Waterflooding-Induced Nonsimultaneously Closed Multistorage Fractures: Semianalytical Model and Case Study

Summary Waterflooding will induce the opening and extension of fractures, which will create some water flow channels. Due to fracture multiclosures, the obtained fracture half-length from conventional finite-conductivity models is less than the actual value, leading to water flow channels that have been formed but not detected by engineers. According to a large number of waterflooding-front matching schematics and interwell connection coefficient analyses, we find that waterflooding usually connects natural fractures to form bi-induced fractures, which will close nonsimultaneously during the falloff test. In this paper, we develop a waterflooding-induced nonsimultaneously closed multistorage fracture model (WNMF) to describe waterflooding-induced fracture characteristics accurately. The bi-induced fractures are separated into multiple segments to calculate their pressure response. The closed induced-fracture conductivities are constant, and the opened induced-fracture conductivities follow the exponential equation measured by the experiments. Induced-fracture interference and multistorage effects are considered. Finally, the Duhamel principle is used to characterize the storage effects of bi-induced fractures and the wellbore. Results show that the type curve of the WNMF model has bi-peaks on the pressure derivative curve, which was regarded as error data in the past. Closed induced-fracture half-length is identified quantitatively. We can obtain an induced-fracture angle by matching the interference flow (an innovative flow regime in this paper), which can guide engineers to prevent and monitor water breakthrough in time. Using the obtained parameters (induced-fracture angle and closed induced-fracture half-length) can guide well pattern encryption and reasonable well location determination. If the induced-fracture angle is 90°, an additional horizontal line will be shown on the pressure derivative curve. When the horizontal line is misidentified as a quasiradial flow regime, the obtained reservoir permeability will be amplified many times. The multistorage coefficient is obtained to correct the magnified storage coefficient. Equation calculation and model matching methods verify each other to improve closed induced-fracture half-length accuracy. In conclusion, the experiment and mathematical model methods work together to describe the pressure response behavior of water injection wells. The WNMF model is compared with the conventional finite-conductivity model to verify its accuracy. A field case demonstrates its practicality.

Precision in Defining Diagnostic Plots Optimizes Well-Test Results

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 206108, “Diagnostic Plots of Pressure-Transient, Rate-Transient, and Diagnostic Fracture Injection/Falloff Tests,” by David Craig, SPE, Occidental, and Thomas Blasingame, SPE, Texas A&amp;M University. The paper has not been peer reviewed. _ All transient-test interpretation methods use diagnostic plots for the identification of wellbore or fracture storage distortion, flow regimes, and other parameters. The associated diagnostic plots are not interchangeable between such tests. The objective of this work is to clearly define the appropriate diagnostic plots for each type of transient test. Introduction In the complete paper, the authors review constant-rate drawdown solutions for a few specific cases of interest and the plotting function used to match buildup data to the drawdown solutions. They extend their review to the cases of buildup or falloff analysis following short flow periods and illustrate the differences between analysis of buildup or falloffs following short and long flow periods. After covering pressure-transient testing, they discuss rate-transient diagnostic plots and the ambiguity observed during analysis of multifractured horizontal well diagnostic plots and the uncertainty of analyst straight lines. Finally, they discuss and demonstrate the correct plotting functions and flow-regime interpretation for diagnostic fracture injection and falloff tests. Multiple examples from the literature are included as part of the discussion. Pressure-Transient Diagnostic Plots Pressure-transient-testing diagnostic plots evolved from the solutions to constant-rate drawdown problems. The authors’ intent is to review infinite-acting solutions for radial flow with wellbore storage and skin and flow through an infinite-conductivity fracture. On a log-log plot, the characteristic slopes, detailed in the complete paper, are unit slope, ½ slope, and zero slope. Many authors have proposed plotting functions for overlaying the observed pressure response from transient tests other than a constant-rate drawdown on the drawdown solutions. In many cases, the slopes identifying storage distortion and flow regimes from drawdown solutions will match and can be used to identify storage and flow regimes from pressure-buildup tests. A situation in which pressure-buildup or falloff test plotting functions fail to match the drawdown solution is when the flow period before shut-in is short. Short-flow transient tests have been reviewed by multiple authors. In lower-permeability reservoirs, pressure-transient tests with short flow periods are very common, and, in unconventional reservoirs, short-flow transient tests are the most-common transient test. Diagnostic plots constructed based on the characteristic shapes of the dimensionless pressure and the dimensionless pressure derivative with respect to the natural logarithm of dimensionless time for constant-rate drawdown solutions cannot be applied in the same manner for short-flow transient tests. With short-flow transient tests, the observed derivative of pressure difference with respect to the natural logarithm of time matches the negative product of dimensionless time and the second derivative of dimensionless pressure with respect to dimensionless time. Additionally, the commonly known impulse derivative, which is defined as the product of time and the derivative of pressure difference with respect to the natural logarithm of time, will match the negative product of dimensionless time squared and the second derivative of dimensionless pressure with respect to dimensionless time.

Application of Temperature Fall-Off Interpretation Method in Superheavy Oil or Oil Sand SAGD Process

SAGD technology has been successfully and widely applied in the development of superheavy oil and oil sand projects. Before normal SAGD process, some preheating ways are often needed to realize interwell hydraulic connection, and this means that determining reasonable SAGD conversion timing from the preheating stage is an essential precondition for good performance. Previous numerical simulations or qualitative analysis of temperature fall-off data are often adopted in the industry, but they have deficiencies in terms of dependent on static geological model or insufficient data utilization. Therefore, on the basis of the temperature and pressure monitoring process comparison in China’s superheavy oil and Canada’s oil sand projects, this paper proposed a temperature fall-off interpretation model to obtain thermal diffusivity and preheating radius at different measurement points along the horizontal section by combining an unsteady thermal conduction model under constant heating power of wellbores in the radial coordinate system and approximately unsteady thermal conduction model with constant wellbore temperature and Fourier’s law of thermal conduction. Besides, the duration time, interpretation method, and application flow chart of temperature fall-off test were presented. Then, it was validated to successfully determine the timing of SAGD conversion from the preheating stage by an example combining with tracking numerical simulation, temperature inflection point analysis, and index analysis during the partial-SAGD and initial SAGD stages. The findings of this study can help determine the SAGD conversion timing from the preheating stage simpler and faster especially for the case of long horizontal well section deployed with more temperature measurement points.

Assessment of Coal Permeability using Injection Falloff Test and Effect of Temperature and Skin Factor on It: A Case Study for Coal Seams of Jamalganj Coalfield, Bangladesh

The Jamalganj coalfield with the coal deposits of the Permian Gondwana Group in the halfgraben basin was discovered in Joypurhat District, Northwestern Bangladesh, sometime in 1962. Individual coalbed thickness ranges from 0.60 m to 42 m and seams were encountered between the depth ranges of 640 m and 1158 m. Since mining has not yet begun due to the greater depth of the coal seams, several researchers have proposed a Coalbed Methane (CBM) exploration in this region. This research focuses on the permeability of the Jamalganj coal derived from the in-situ Injection Falloff Test (IFT), which is an important reservoir parameter and one of the key factors in CBM exploration and Underground Coal Gasification (UCG). In addition to that, the relationship of temperature and skin factor with permeability is one of the key findings of this research, permeability obtained from the IFT ranges from 2.57 to 121.16 mD while the skin factor ranges from - 6.11 to 50.85 and a higher temperature gradient as of about 4°C per 100 m depths was observed. The study shows that temperature has an inverse relationship with the permeability that decreases with depth and temperature increases, which is analogous with the other CBM producing reservoirs around the world. The negative skin factor denotes flow enhancement near the wellbore and a well-stimulated reservoir, and the positive skin factor indicates increased flow resistance near the wellbore, which reduces permeability. The permeability data suggest that the analyzed coal seams of the Jamalganj Coalfield are suitable for unconventional gas production by either CBM or UCG development. The Dhaka University Journal of Earth and Environmental Sciences, Centennial Special Volume June 2022: 103-112

Port-Opening Falloff Test: A Complementary Test to Diagnostic Fracture Injection Test

Summary Conventional fracture injection/falloff tests, such as minifrac or diagnostic fracture injection test (DFIT), are commonly used to characterize shale and tight reservoirs. For ultralow-permeability reservoirs, a reliable DFIT requires a long falloff period after a short injection period. A long falloff observation period of weeks or months is often not economically viable. In addition, the recent economic downturn requires operators to seek cost-effective alternatives to further optimize expenditures. An alternative to a DFIT is a port-opening falloff test (POFOT). Many horizontal completions use a pressure-activated sleeve in the toe of the well to provide formation access after the casing integrity test. Most sleeves open at a pressure in excess of the formation breakdown pressure, after which the wellbore pressure declines toward reservoir pressure. This study first introduces the concept of the POFOT as a novel physical test. A new test method must demonstrate that it accesses the formation of interest and that the data obtained are applicable. A workflow is developed to demonstrate this and is applied to falloff data from POFOTs conducted in five horizontal wells completed in five formations. The results show that the fluid leaving the port is highly likely to break down both the cement sheath and the matrix and create a fracture which then closes. Observation of the well pressure after port opening resembles that from a DFIT. However, without a fixed-duration and constant-rate injection period, there is no accepted method to apply. Nevertheless, both qualitative and quantitative analyses of the falloff data provide a good estimation of reservoir pressure with a reasonable approximation of fracture closure when compared with the estimates from DFIT analysis from offset wells. The key challenges in parameter estimation, besides the development of an appropriate analysis method, are short falloff data and noisy early-time data due to wellbore resonance (WBR), low-resolution gauges, and change in sampling frequency.

Technology Focus: Heavy Oil (April 2022)

Heavy oils are characterized by high density, high viscosity, and high-heavy-fraction components. Because of high viscosity and lower API gravity than conventional crude oil, primary recovery of some of these crude oil types requires thermal stimulation of the reservoirs. Most of the technologies that deal with heavy oil need to address the mobility ratio or viscous forces before any flooding. In general, poor recovery is caused by physical reasons or geological reasons. Physical reasons can be categorized as capillary forces (existence of the interfacial tension between oil and water, wettability) or viscous forces (high mobility ratio between water and oil). Geological reasons are heterogeneities in reservoir rock and exist in all petroleum oil systems. In heavy oil reservoirs, enhanced oil recovery (EOR) intends to reduce the capillary forces and interfacial tension to improve microscopic displacement efficiency or improve the sweep efficiency (macroscopic) by reducing the mobility ratio between injected fluid and displaced fluid. Improving the mobility ratio is achieved by increasing the viscosity of water using polymers or by reducing the oil viscosity using heat. In general, all technologies need to address the capillary and viscous forces to improve oil recovery. Paper SPE 207361 discusses improving of the efficiency of the flood by near-wellbore conformance and improving the vertical sweep efficiency. The use of fiber-optic sensors, as addressed in paper SPE 199023, is intended to gather better data and avoid misinterpretation during falloff tests and injectivity tests. Traditionally, for heavy oil EOR simulation, because of the addition of chemical species or heat to the flow equations as well as the need for a finer grid resolution, the use of the full-field model in most cases was limited and the use of sector models and local grid refinement to obtain a reasonable accuracy has been applied in the industry. Sector modeling conditions must be satisfied to establish the reliability and the trade-off between accuracy (sector models) and computational expediency (full-field model). Recent development of hardware and software [graphics-processing-unit (GPU) -based simulators] has provided the industry with the tools to achieve a full-field model simulation in most fields by taking advantage of GPU solvers and using a fine-grid model to predict full-field performance. Recommended additional reading at OnePetro: www.onepetro.org. SPE 200279 - Field Application of the Autonomous Inflow Control Device for Optimized Heavy Oil Production in South Sultanate of Oman by Ali Al-Jumah, Petroleum Development Oman, et al. SPE 203012 - More Oil and Less Water: Autonomous Inflow Control Devices in New and Old Producers in Heavy Oil Fields From South of Oman by Ameera Al Harrasi, Petroleum Development Oman, et al. SPE 207684 - Game Changer in Dealing With Hard Scale Using a Slickline Torque Action Debris Breaker by Mahmoud Mohamed Koriesh, Dragon Oil, et al.

Field Demonstration of the Impact of Fractures on Hydrolyzed Polyacrylamide Injectivity, Propagation, and Degradation

Summary During a polymer flood, the field operator must be convinced that the large chemical investment is not compromised during polymer injection. Furthermore, injectivity associated with the viscous polymer solutions must not be reduced to where fluid throughput in the reservoir and oil production rates become uneconomic. Fractures with limited length and proper orientation have been theoretically argued to dramatically increase polymer injectivity and eliminate polymer mechanical degradation. This paper confirms these predictions through a combination of calculations, laboratory measurements, and field observations (including step-rate tests, pressure transient analysis, and analysis of fluid samples flowed back from injection wells and produced from offset production wells) associated with the Kalamkas oil field in Western Kazakhstan. A novel method was developed to collect samples of fluids that were back-produced from injection wells using the natural energy of a reservoir at the wellhead. This method included a special procedure and surface-equipment scheme to protect samples from oxidative degradation. Rheological measurements of back-produced polymer solutions revealed no polymer mechanical degradation for conditions at the Kalamkas oil field. An injection well pressure falloff test and a step-rate test confirmed that polymer injection occurred above the formation parting pressure. The open fracture area was high enough to ensure low flow velocity for the polymer solution (and consequently, the mechanical stability of the polymer). Compared to other laboratory and field procedures, this new method is quick, simple, cheap, and reliable. Tests also confirmed that contact with the formation rapidly depleted dissolved oxygen from the fluids—thereby promoting polymer chemical stability.

Machine-Learning Techniques Assist Data-Driven Well-Performance Optimization

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201696, “Robust Data-Driven Well-Performance Optimization Assisted by Machine-Learning Techniques for Natural-Flowing and Gas-Lift Wells in Abu Dhabi,” by Iman Al Selaiti, Carlos Mata, SPE, and Luigi Saputelli, SPE, ADNOC, et al., prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, Colorado, 5–7 October. The paper has not been peer reviewed. Despite being proven to be a cost-effective surveillance initiative, remote monitoring is still not adopted in more than 60% of oil and gas fields around the world. Understanding the value of data through machine-learning (ML) techniques is the basis for establishing a robust surveillance strategy. In the complete paper, the authors develop a data-driven approach, enabled by artificial-intelligence methodologies including ML, to find an optimal operating envelope for gas-lift wells. Real-Time Well-Performance Optimization Wellsite Measurement and Control. - Flow Tests. - Past tests include sporadic measurement of multiphase rates and the associated flowing pressure and temperature, collected at various points of the production system, from bottomhole to separator conditions. Flow tests are also known as well tests; however, the authors use the term “flow test” in this paper to avoid confusion with well testing as used in pressure transient tests, including temporary shut-in pressure buildups (for producers) and pressure falloff tests (for injectors). Normally, a well would have limited data points from the past well tests (i.e., less than 50 valid flow tests in a period of 5–10 years). This data is the basis of creating ML models. Continuous Monitoring. - Every well should have adequate instrumentation, and its supporting infrastructure should include reliable power supply, minimum latency telemetry, and desktop access to production parameters. Alignment among real-time data and relational databases is required. Remote Control and Automated Actuation. - In addition to controllable valves, every well should be enabled with actuators to control the process variables. Remote control allows the operator to make changes to the current well-site configuration. Regulatory and Supervisory Control. - The value of automated closed-loop regulatory and supervisory control is to sustain optimal production while providing high well availability. Real-Time Production Optimization. - Continuous production optimization means that expected performance is challenged frequently by updating an optimal forecast with upper-level targets and current asset status. This is achieved by applying actions that close the gap between actual and expected performance. Faster surveillance loops compare actual vs. expected performance to determine minute, hourly, and daily gaps. A slower surveillance loop updates the asset’s expected performance. Well-Management Guidelines. - These are established, known limits to address and honor restrictions such as concession-contract obligations and legal limits, optimal reservoir management, flow assurance, economics, safety, and integrity.

Permeability measurements using rate-transient analysis (RTA): Comparison with different experimental approaches

Reservoir engineers commonly apply rate-transient analysis (RTA) and pressure-transient analysis (PTA) methods to analyze multi-fracture horizontal wells (MFHWs) completed in unconventional reservoirs quantitatively for reservoir and hydraulic fracture properties. Data from core analysis techniques are commonly used to provide important input for RTA-PTA models. However, conventional laboratory techniques (i.e., steady-state and non-steady-state fluid flow) do not reproduce the operating conditions that MFHWs are subjected to in the field. In the current work, laboratory techniques that better reproduce these boundary conditions are explored and compared to more traditional core analysis methods.For this study, RTA methods are applied to gas produced from core plugs and PTA methods are applied to gas injection-fall-off data at the start of the core test before gas production. While the RTA method has been previously described by the authors, the application of the PTA method to provide an early, and fast, estimate of permeability is unique to this study. Further, our previous experimental setup for performing RTA was modified to accommodate not only the use of both RTA/PTA methods, but also the use of conventional core analysis methods (steady-state and non-steady-state methods) to allow for direct comparison of all methods.For both RTA and PTA core tests, the observed flow-regime sequence is transient linear flow followed by boundary-dominated flow, which is the same sequence that is commonly observed in the field for MFHWs producing from low-permeability and shale reservoirs. Two independent permeability values were estimated using the slope of the square root time plot and the time at the end of linear flow for each test. The pore volume of the samples were also estimated using the RTA method. Permeability and pore volume values obtained from the RTA method, referred to as ‘RTAPK’ previously, were in good agreement with those obtained from more conventional core testing methods (average coefficient of variation = 8%). The derived permeabilities from the time at the end of linear flow during the fall-off test were close to other permeabilities. In contrast, the square root time plot (fall-off) resulted in significantly higher permeabilities attributed to the experimental artifact caused by substantial dead volume in the injection port. The primary advantage of the RTA core analysis method is the accelerated test-time. For samples with permeability values ranging between 0.1 and 3 mD, the apparent gas permeabilities can be estimated in less than 3 to 10 minutes using both fall-off and production data.

Analytical solutions for injectivity and falloff tests in stratified reservoirs with multilateral horizontal wells

The availability of analytical solutions to analyze injectivity and falloff tests is desired to estimate well injectivity performance and reservoir parameters owing to their simplicity in interpreting pressure transient data acquired during such tests. However, the currently available analytical solutions can only describe injectivity and falloff tests in single-layer reservoirs with horizontal wells and multilayer systems with vertical wells. Therefore, the main purpose of this work is to develop new analytical solutions that can be used to accurately interpret and analyze injectivity and falloff tests conducted in multilayer reservoirs drilled by multilateral horizontal wells under two-phase flow. The presented solutions showed a good agreement with the results obtained from a general purpose commercial reservoir simulator. Moreover, the proposed solutions can be used to accurately estimate the reservoir equivalent permeability and also as forward models for nonlinear regression techniques and history matching methods.

Pressure falloff testing to characterize CO2 plume and dry-out zone during CO2 injection in saline aquifers

The fluid mobilities and the lateral extent of the CO2 plume and the dry-out zone are among important unknowns required to effectively manage CO2 storage in saline aquifers projects. These unknowns can be derived from pressure falloff testing which has been widely used to characterize the subsurface. This work provides a three-region analytical solution for falloff pressure during the infinite-acting period of CO2 injection in saline aquifers. The solution is derived using Laplace transformation technique of the governing diffusivity equations and the accompanying initial and boundary conditions. The exact solution is validated against numerical results obtained from a black-oil reservoir simulator for two cases. The solution is approximated into simple forms in real-time domain considering different time periods. Then, a graphical semi-log analysis technique based on the approximate solutions is provided as an interpretation tool of falloff tests where the fluid mobilities and the extents of dry-out zone and CO2 plume can be inferred. The interpretation technique is applied to synthetic falloff test data to investigate its potential and reliability.

Classification of Coal Structure Combinations and Their Influence on Hydraulic Fracturing: A Case Study from the Qinshui Basin, China

Coal structure directly correlates to permeability and hydraulic fracturing effects. Underground coal mining indicates that a single coal section generally contains multiple coal structures in superposition, making how to recognise the coal structure combination and predict its influence on coal permeability a challenging problem. Based on well-drilling sampled cores, the geological strength index (GSI), and well-logging data, the DEN, GR, CALX, and CALY were selected to establish a model to predict GSI by multiple regression to identify coal structure from 100 coalbed methane wells. Based on fitting GSI and corresponding permeability test values, injection fall-off (IFO) testing, and hydraulic fracturing results, permeability prediction models for pre- and post-fracturing behaviour were established, respectively. The fracturing effect was evaluated by the difference in permeability. The results show that a reservoir can be classified into one of nine types by different coal structure thickness proportion (and combinations thereof) and the fracturing curves can be classified into four categories (and eight sub-categories) by the pressure curve. Up-down type I and type II reservoirs (proportion of hard coal &gt;60%) and intervening interval type I reservoir (proportion of hard coal &gt;70%) are prone to form stable and descending fracturing curves and the fracturing effects are optimal. Intervening interval type II (hard coal:soft coal:hard coal or soft coal:hard coal:soft coal ≈1:1:1) and up-down type III (hard coal:soft coal =1:1) form descending type II, rising type I and fluctuating type I fracturing curves and fracturing effect ranks second; up-down type IV and V (proportion of hard coal &lt;40%), interval type III (proportion of hard coal &lt;30%), and multi-layer superposition-type reservoirs readily form fluctuating and rising fracturing curves and fracturing effects therein are poor. The research results provide guidance for the targeted stimulation measured under different coal structure combinations.

A two-step semi-analytical solution method for the pressure response during cold water injection for a vertical well in a warm bounded reservoir

Development of a mathematical solution for injection/falloff problem of an oil-water system for transient data analysis is complicated due to the presence of two mobile phases that create a moving discontinuity. The solutions that have been developed in the past are based on a series of assumptions that make the models limited. The previous models have neglected one or more of the key reservoir and well parameters such as the variation of saturation in the invaded zone, temperature effects, wellbore storage, skin and outer boundary conditions. In this work, a generalized two-step semi-analytical solution method is presented to precisely simulate the pressure transient behaviour for injection and falloff tests following cold water injection for a fully-penetrating vertical well in a warm and bounded oil reservoir in the presence of skin and wellbore storage. The formulated model uses two simplistic steps to solve the complex mathematical problem and improve computational efficiency. The usage of the Laplace-transform finite-difference method to solve the system of equations eliminates the need for temporal discretization, thereby resolving issues related to convergence and time iterations by allowing an unlimited timestep size without the loss of stability and accuracy. The accuracy and consistency of the proposed solution method are assessed by comparing the results with that of ECLIPSE 100 and an excellent agreement is observed. The results suggest that the injection period pressure behaviour is vastly influenced by the injected water propagation under cold conditions, whereas, the falloff period pressure behaviour provides information of the water bank under cold conditions and the uninvaded zone under hot conditions. The comparison of the non-isothermal and isothermal pressure behaviour shows that the isothermal model can be improved using modified fluid viscosities to match the non-isothermal pressure behaviour that not only could minimize the mathematical complications, but also the computation time.