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Abstract Market-induced production shut-downs and restarts offer us an opportunity to gather step-rate and shut-in data for pressure transient analysis (PTA) and rate transient analysis (RTA). In this study, we present a unified transient analysis (UTA) to combine PTA and RTA in a single framework. In this new approach continuous production data, step-rate data, shut-in data and re-start data can be visualized and analyzed in a single superposition plot, which can be used to estimate both and infer formation pore pressure in a holistic manner by utilizing all available data. Most importantly, we show that traditional log-log and square root of time plots can lead to false interpretation of the termination of linear-flow or power-law behavior. Field cases are presented to demonstrate the superiority of the newly introduced superposition plot, along with discussion on the calibration of long-term bottom-hole pressure with short-term measurements.
Elechi, Virtue Urunwo (Ace-Cefor, University of Port Harcourt) | Ikiensikimama, Sunday Sunday (University of Port Harcourt) | Akaranta, Onyewuchi (University of Port Harcourt) | Ajienka, Joseph Atubokiki (University of Port Harcourt) | Onyekonwu, Mike Obi (University of Port Harcourt) | Okon, Okon Efiong (University of Port Harcourt)
Abstract As deep-water activities and development into deeper operations (depth of 6,000ft or more) increases, temperatures and pressures become favorable for hydrate nucleation and growth. This results in additional risk and challenges as to how to prevent formation of gas hydrates. This paper takes a look at the performance of a local surfactant derived from plant material in a laboratory mini flow loop made of a 0.5-inch internal diameter 316 stainless steel pipe enclosed in a 4-inch PVC pipe mounted on an external metal frame work. The performance of the local surfactant (Surf. X) was compared with that of the conventional hydrate inhibitor N-Vinyl Caprolactam (N-VCap). Varying weights of Surf. X were evaluated in the laboratory mini flow loop. Pressure versus Temperature, change in Pressure versus Time plots showed that Surf. X performed better than the conventional N-VCap in almost all the concentrations considered (except at 0.04wt %). The optimum concentration for inhibition was 0.02wt% with inhibition efficiency of 81.58% while that of N-VCap was 77.19%. The inhibition efficiency of Surf. X for 0.01, 0.03 and 0.04wt % were 72.81% and 75.44% respectively. Surf. X is locally sourced, readily available in commercial quantity and also eco-friendly because it is plant based unlike the N-VCap which is toxic and expensive. It is advised that the local surfactant X be developed as an alternative to the conventional inhibitor for gas hydrate inhibition.
Elechi, Virtue Urunwo (University of Port Harcourt, World Bank Africa Center of Excellence for Oilfield Chemicals Research, ACE-CEFOR) | Ikiensikimama, Sunday Sunday (University of Port Harcourt) | Ajienka, Joseph Atubokiki (University of Port Harcourt) | Akaranta, Onyewuchi Emmanuel (University of Port Harcourt) | Onyekonwu, Mike Obi (University of Port Harcourt) | Okon, Okon Efiong (University of Port Harcourt)
Abstract This paper takes a look at the performance of a Locally Sourced Material (LSM) in a laboratory mini flow loop of ½ -inch internal diameter, made from 316 stainless steel pipe sheathed in a 4-inch PVC pipe built on an external metal frame work. The performance of the LSM was measured with that of the conventional hydrate inhibitor 2-(Dimethylamino)ethylmethacrylate (2-DMAEM). The performance evaluation was based on Pressure versus time, change in pressure versus time and initial and final pressure versus time plots. These plots showed that LSM performed better than the conventional 2-DMAEM in all the weight percentages considered (0.01wt% −0.03wt %). The optimum weight percentage for inhibition was 0.02wt% with inhibition efficiency of 81.58% while that of 2-DMAEM was 73.68%. The inhibition efficiency for 0.01wt% and 0.03wt% of LSM wereboth 72.81% whereas that of 2-DMAEM were 51.75% and 76.32% respectively. The LSM is locally sourced, readily available in commercial quantity and also eco-friendly because it is plant based unlike the 2-DMAEM which is toxic and expensive. It is advised that the LSM be developed as an alternative to the conventional inhibitor for gas hydrate inhibition.
Taqi, Fatma (Kuwait Oil Company) | Ahmad, Khalid (Kuwait Oil Company) | Garcia, Jose G. (Kuwait Oil Company) | Zhang, Ian (Shell) | Zijlstra, Ellen (Shell) | Ayyad, Hazim (Schlumberger) | Alajmi, Sarah (Schlumberger) | Harrison, Christopher (Schlumberger) | Sullivan, Matthew (Schlumberger)
Abstract A shallow, unconsolidated, sour heavy oil reservoir in North Kuwait is under primary production. Due to rapid decline in reservoir pressure, a development scenario was selected consisting of 10 years of water injection secondary recovery followed by enhanced oil recovery (EOR) polymer flood for which a pilot is being implemented. This pilot will provide vital information to establish feasibility for full-field implementation and in this paper, we describe the application of Interference Pressure Transient Test (IPTT) and stress testing. IPTT is utilized for proper understanding of the vertical permeability and permeability anisotropy (Kv/Kh) which are key for evaluating heavy oil sweep efficiency under injection. Stress testing will provide essential information about the cap rock integrity to monitor that water and polymer flooding is contained across the required reservoir. A combination of IPTT and stress testing utilizing the Wireline Formation Testing (WFT) tool and laboratory core analysis were the basis of a selected method for vertical permeability and permeability anisotropy determination. Laboratory measurement for permeability anisotropy has its own challenge due to unconsolidated nature of the formation. IPTT under such conditions can provide reliable and fast measurements, which can also help to calibrate the laboratory measurements later. Four EOR pilot vertical injectors wells were drilled in a symmetric 5-spot pattern, with a central vertical producer. Distance between the injectors is 60 meters, whereas each injector is at 50 meters spacing from the central producer. IPTT was carried out in all four EOR pilot wells, whereas this study involves only three of the injectors. Three-probe configuration along with advanced three-dimensional probe provided comprehensive evaluation for the sand and shaly reservoir intervals. It was observed that main sand body under consideration showed Kv/Kh ranging between 0.05 to 0.15. Some of the main shaly intervals were observed to be either fully isolating the sub-layers or have some vertical communication. It should be noted that downhole fluid analysis and sampling was conducted in one of the wells utilizing WFT. The obtained fluid properties were included in the IPTT analysis for more accurate results. The acquired data from three pilot wells were used to update the reservoir simulation models to have a more representative sweep efficiency evaluation utilizing polymer flooding for the planned EOR. It provides an efficient way to derive the vertical permeability and permeability anisotropy in the challenging unconsolidated formation. This paper adds to the literature of case studies where vertical permeability and permeability anisotropy have been obtained in the challenging environment of unconsolidated formation. It demonstrates how accurate planning combined with advanced technology and innovative workflow yielded the required input data for the dynamic reservoir simulation model.
Abstract Straight-line analysis (SLA) methods, which are a sub-group of model-based techniques used for rate-transient analysis (RTA), have proven to be immensely useful for evaluating unconventional reservoirs. Transient data can be analyzed using SLA methods to extract reservoir/hydraulic fracture information, while boundary-dominated flow data can be interpreted for fluid-in-place estimates. Because transient flow periods may be extensive, it is also advantageous to evaluate the volume of hydrocarbons-in-place contacted over time to assist with reserves assessment. The new SLA method introduced herein enables reservoir/fracture properties and contacted fluid-in-place (CFIP) to be estimated from the same plot, which is an advantage over traditional SLA techniques. The new SLA method utilizes the Agarwal (2010) approach for CFIP estimation, extended to variable rate/pressure data for low permeability (unconventional) reservoirs. A log-log plot of CFIP versus material balance time (for liquids) or material balance pseudo-time (for gas) is created, which typically exhibits power-law behavior during transient flow, and reaches a constant value (original fluid-in-place, OFIP) during boundary-dominated flow. Although CFIP calculations do not assume a flow geometry, the SLA method requires this to extract reservoir/fracture information. Herein, transient linear flow is assumed, and used for the SLA method derivation, which allows the linear flow parameter (LFP) to be extracted from the y-intercept (at material balance time or material balance pseudo-time= 1 day) of a straight-line fit through transient data. OFIP can also be obtained from the stabilization level of the CFIP plot. Validation of the new SLA method for an undersaturated oil case is performed through application to synthetic data generated with an analytical model. Thenew SLA results in estimates of LFP and OFIP that are in excellent agreement with model input (within 2%). Further, the results are consistent with the traditional SLA methods used to estimate LFP(e.g. the square-root of time plot) and OFIP (e.g. the flowing material balance plot). Practical application of the new SLA method is demonstrated using field cases and experimental data. Field cases studied include online oil production from a multi-fractured horizontal well (MFHW) completed in a tight oil reservoir, and flowback water production from a second MFHW, also completed in a tight oil reservoir. Experimental (gas) data generated using a recently-introduced RTA core analysis technique, were also analyzed using the new SLA method. In all cases, the new SLA method results are in excellent agreement with traditional SLA methods. The new SLA method introduced herein is an easy-to-apply, fully-analytical RTA technique that can be used for both reservoir/fracture characterization and hydrocarbons-in-place assessment. This method should provide important, complementary information to traditionally-used methods, such as square-root of time and flowing material balance plots, which are commonly used by reservoir engineers for evaluating unconventional reservoirs.
Abstract Diagnostic plots of production decline of wells producing from unconventional reservoirs provide a particularly interesting field of study, given the fast-growing unconventional completion methods in the United States. In this paper, we present a method for analyzing fracture quality in horizontal wells with multiple stages of fracturing draining unconventional reservoirs. Our method, which explains a plausible cause for reduced production and rapid production decline, includes a log-log plot of the inverse production rate change vs. time. This diagnostic plot was used to analyze forty oil-producing wells drilled in the Bakken formation and ten gas wells producing from the Marcellus formation. From these graphs, we first observed that regardless of the number of fracturing stages, a plot of a system of fractures behaves as one equivalent fracture. Second, we noted that in some cases; a bilinear flow is observed, indicating strong support of the induced fractures by the formation. This is followed by a linear flow period. Furthermore, the duration of fracture linear flow indicates the quality of the induced fracture system in the formation. Crossflow among the induced fractures is noted. This can explain the deterioration of well productivity. A summary of these observations and the appropriate explanation behind this analysis method is presented. This diagnostic method used can help in monitoring causes of low production quality and low recovery factor from individual wells and in seeking solutions.
Vahedian, A. (University of Calgary) | Clarkson, C. R. (University of Calgary) | Ghanizadeh, A. (University of Calgary) | Zanganeh, B. (University of Calgary) | Song, C. (University of Calgary) | Hamdi, H. (University of Calgary)
Abstract Estimation of matrix permeability is critical for evaluating the long-term economic viability of unconventional reservoirs. Currently, a variety of techniques (e.g. pulse-decay, crushed-rock) are used to measure gas permeability of tight rocks in the laboratory. However, these laboratory-based methods are not fully representative of different gas flow regimes that are encountered during field production. In this work, a new experimental setup, and previously-developed rate-transient analysis (RTA) techniques, are combined to mimic field-scale well-test/production data in the laboratory for the determination of representative matrix permeability and pore volume in tight rocks. A new experimental set-up comprised of a vacuum pump, a series of (back-pressure) valves, a high-precision pressure transducer and flowmeter was developed to simulate gas well-test/production scenarios in the laboratory. The experimental procedure involves injection of gas (CH4) into one end of a core plug (monitoring the pressure until equilibrium), followed by constant flowing pressure gas production from the same end that gas was injected. For analysis of the data, a log-log plot of flow rate versus time is used to first identify the flow regimes during the production phase. Using previously-derived RTA algorithms, permeability is then estimated using the slope of the square-root of time plot (if transient linear flow is observed) and distance of investigation calculation (if the end of linear flow is observed). In order to test the new apparatus, experimental procedures and RTA algorithms, two experiments under similar experimental conditions were conducted on a core plug from the Montney Formation, which was previously analyzed using more conventional methods. The flow-regimes identified during the production cycle were linear flow followed by boundary-dominated flow for the two experiments. The square-root of time plot yielded permeability estimates of 0.00067 and 0.00072 md from tests A and B, respectively - the distance of investigation (DOI) approach yielded a permeability estimate of 0.00069 md for both tests. The results of the two experiments are in reasonable agreement (maximum discrepancy < ± 20%) with permeability measured using the more conventional pulse-decay technique with methane as the analysis gas (0.00084 md). Standard laboratory techniques for the determination of permeability in tight rocks are not fully representative of fluid flow mechanisms that occur during field-scale production. Routine laboratory-based methods either use samples that are not representative of the "in-situ " reservoir rock (e.g. crushed-rock samples) or represent only unidirectional fluid flow through the core plug samples (e.g. pulse-decay and steady-state techniques) that does not account for heterogeneity observed in the field. Integrating the previously-developed rate-transient analysis techniques with a new experimental set-up, the core testing procedure proposed herein represents a novel approach to the evaluation of tight rock permeability, better simulating field-scale production than previous approaches.
Abstract A new method is proposed to estimate the compliance and conductivity of induced unpropped fractures as a function of the effective stress acting on the fracture from DFIT data. A hydraulic fracture's resistance to displacement and closure is described by its compliance (or stiffness). Fracture compliance is closely related to theelastic, failure and hydraulic properties of the rock. Quantifying fracture compliance and fracture conductivity under in-situ conditions is crucial in many earth science and engineering applications but very difficult to achieve. Even though laboratory experiments are often used to measure fracture compliance and conductivity, the measurement results are strongly influenced by how the fracture is created, the specific rock sample obtained andthe degree to which it is preserved. As such the results may not be representative of field scale fractures Over the past two decades, Diagnostic Fracture Injection Tests (DFIT) has evolved into a commonly used and reliable technique to obtain in-situ stresses, fluid leak-off parameters and formation permeability. The pressure decline response across the entire duration of a DFIT test reflects the process of fracture closure and reservoir flow capacity. As such it is possible to use this data to quantify changes in fracture conductivity as a function of stress. In this paper we presenta single, coherent mathematical framework to accomplish this. We show how each factor impacts the pressure decline response and the effects of previous overlooked coupled mechanisms are examined and discussed. Synthetic and field case studies are presented to illustrate the method. Most importantly,a new specialized plot (normalized system stiffness plot) is proposed, which not only providesclear evidence of the existence of a residual fracture width as afracture is closing during a DFIT, but also allows us to estimate fracture compliance (or stiffness) evolution and infer un-propped fracture conductivity using only DFIT pressure and time data based on a time-convolution solution. It is recommended that the normalized system stiffness plot be used as a standard practice to complement the G-function or square root of time plotbecause it provides veryvaluable information on the properties of fracture surface roughness at a field-scale, information that cannot be obtained by any other means.
Abstract Over the past two decades, Diagnostic Fracture Injection Tests (DFIT) or Injection-Fall-off Fracture Calibration Tests have evolved into a commonly used and reliable technique to evaluate reservoir properties, fracturing parameters and obtain in-situ stresses. Since the introduction of DFIT analysis based on G-function and its derivative, this method has become standard practice for quantifying minimum in-situ stress and leak-off coefficient. However, the pressure decline model that underlies the G-function plot makes two distinct and important assumptions: (1) leak-off is not pressure-dependent and, (2) fracture stiffness (or compliance) is assumed to be constant during fracture closure. Fracture closure is a gradual process that starts when asperities at the fracture tip first come into contact with each other. As pressure declines due to leak-off, more and more of the fracture wall comes into contact. It is important to model this process quantitatively to obtain good estimates of in-situ stresses and leak-off. In this paper, we present a model that accounts for changes in fracture stiffness/compliance as the fracture closes, with leak-off that is dependent on fracture pressure. The model is, therefore, capable of analyzing DFIT data from the end of pumping to days or even weeks after shut-in. We first review Nolte's original G-function model and examine the assumptions inherent in the model. We then present a new global pressure transient model for pressure decline after shut-in which not only preserves the physics of unsteady-state reservoir flow behavior, elastic fracture mechanics and material balance, but also incorporates the gradual changes of fracture stiffness/compliance due to the contact of rough fracture walls during closure. This global model allows us to analyze the whole spectrum of DFIT data by bridging before closure and after closure data seamlessly. Analysis of synthetic cases, along with field data are presented to demonstrate how the coupled effects of fracture geometry, fracture surface asperities, formation properties, pore pressure and wellbore storage can impact fracturing pressure decline and the estimation of minimum in-situ stress. It is shown that so-called "normal leak-off" behavior that is modeled using Carter leak-off is an oversimplification that leads to significant errors in the interpretation of the data. All the before closure analysis conducted under a "normal leak-off" assumption should be reexamined cautiously. Most importantly, this article reveals that previous methods of estimating minimum in-situ stress often lead to significant over or underestimates, because of their failure to account for changes in fracture stiffness/compliance correctly as the fracture closes progressively from the edge to the center. Based on our modeling and simulation results, we propose a much more accurate and reliable method to estimate the minimum in-situ stress, fracture pressure dependent leak-off rate and evaluate the compliance of the un-propped fracture.
Abstract Although material balance time was originally proposed by Blasingame and co-workers to model wells in boundary-dominated flow, later investigators proposed that logarithmic rate vs. material balance time lead to the same conclusions as logarithmic rate vs. time plots during transient flow for smoothly changing rates and are superior for identifying and analyzing data in boundary-dominated flow. However, application of this idea to field data often shows different curve shapes for the two methods of plotting during transient flow. The purpose of this study was to identify the cause of this discrepancy and to suggest an approach to flow regime identification in which we might have more confidence. Our hypothesis was that the cumulative production used in calculating material balance time will not be consistent with the rates during transient flow for multi fracture horizontal wells (MFHW), completed in ultra-low permeability reservoirs, whenfracture damage was present (more common than not) and pressure drawdown and production varied during the early months of a well's production history. To test our hypothesis, we analyzed simulated production data in several ways:production at constant BHP, no fracture damage; variable BHP, no fracture damage, BHP values known as functions of time; variable BHP, no fracture damage, BHP values unknown; constant BHP with fracture damage; variable BHP with fracture damage and known BHP; and variable BHP with fracture damage and unknown BHP. We found that our hypothesis was correct, and that, during transient linear and bilinear flow, the slopes of logarithmic plots of rate vs. time and rate vs. material balance time can be quite different. Linear and bilinear flow can be identified with a slope of (-1/2) and (-1/4) on logarithmic rate-time plot for smoothly decreasing rates. However, they can be delayed or disguised significantly on logarithmic rate-MBT plots with large fracture skin and varying BHP. We conclude that a simple logarithmic rate-time plot leads to a more definitive identification and analysis of the transient flow regime in MHFWs than the logarithmic rate-material balance time plot. On the rate-time plot, transient linear and bilinear flow can be identified with a (-1/2) and a (-1/4) slope which may be delayed or distorted on the rate-material balance time plot. For boundary-dominated flow identification and analysis, the material-balance-time plot remains the preferred method.