Radial Injectivity of an Associative Polymer for EOR

Carbonate matrix stimulation of tight and high temperature formations is challenging. The use of retarded acids is inevitable to allow deep acid penetration in those cases. Recently, polymer free delayed acid (PFDA) systems were introduced as a low friction acid system with superior performance. This study presents a comparison between the two delayed acids under linear flow (lab scale) and radial flow (field scale). Linear core flow experiments were conducted using limestone and dolomite cores at temperatures from 200°F to 300°F. 15%, 20%, and 28% HCl based delayed acid systems were tested. 6 in. and 20 in. cores were used in those tests. The information from the linear experiments for both systems were utilized to build a model for those acid systems. An upscaling scheme based on changing the flow area and the wormholes number as a function of acid penetration was realized. The upscaled model was calibrated using radial experiments and in agreement with field observations. The linear experiments have revealed that in limestone both acid systems provide PVBT values less than 1, even at injection rates as low as 0.5 cc/min. The 20 in. core experiments have shown that PFDA has better performance than emulsified acid at both low and high injection rates. The upscaled model has showed that injecting only 30 gal/ft. of PFDA or emulsified acid at low injection rate (0.1 gal/min.ft) can produce 9.3 ft. and 7.8 ft. wormholes, respectively. PFDA with dolomite experiments have shown PVBT values less than 1 PVBT while emulsified acid with dolomite experiments have shown values in the range of 2 PVBT. The radial model has shown that injecting 30 gal/ft. of emulsified acid at 0.1 gal/min. ft. can generate ~4 ft. wormhole (-2.8 skin). On the other hand, injecting PFDA in dolomite formation at the same conditions can yield 9.3 ft. wormhole (-3.64 skin). This value agrees with the field results of treating tight dolomite formation with PFDA. This paper presents an experimentally validated model for PFDA and emulsified acid. The upscaled model agrees with field treatments and allows comparison between the two systems at the well scale. PFDA outperform emulsified acid in treating carbonate formations.

Summary Recent developments in the modeling and prediction of pressure transient tests for various reservoir and flow conditions have indicated the similarities in response that may exist among totally different cases. Several case studies are used to point out pitfalls associated with force-fitting a particular flow regime or reservoir condition on a set of pressure vs. time data. Introduction Current diagnostic procedures used to select a reservoir flow model to interpret well tests include various plots of pressure drop or pressure recovery vs. some function of time. These plots include log ?p vs. log ?t, log-log plot; p vs. log ?t, semilog plot; p vs. ?t, linear flow plot; p vs. 4?t, bilinear flow plot; and p vs. (1/?t), spherical flow plot. The utility of these plots has been shown in a series of published papers during the past decades. A review of these was made recently by Ramey.1 With the advances in analytical and numerical modeling of flow problems in reservoirs, many papers have discussed modeling the response of an idealized reservoir geometry or flow regime under the conditions of a given wellbore flow. Because of many possibilities that may exist in real situations, many investigators are working to formulate and to obtain the pressure response in reservoirs of increasing complexity. Real-life examples of pressure data to fit a given idealized model are often nonexistent. Consequently, many authors use synthetic data to point out the use of their proposed technique or model. In fact, practicing engineers now are reading about many techniques and models for which there may never be examples of actual data to fit. Some people may even criticize the enormous effort toward prediction of pressure response in certain idealized models. One must note, however, that all the idealized cases published to data and yet to be published are opening our eyes to response similarities that may exist among the performance of completely different systems. The purpose of this paper is to present a few examples, make a comparison between the responses of various reservoir models, and point out the errors in interpretation if the radial flow model is forced on the data in all cases. Reservoir Flow Models Reservoir geometry and kz/kr are the two major factors controlling the nature of flow between the high-pressure portion of the field and the wellbore. Fig. 1 shows examples where cases of radial, linear, and spherical flow may develop. The bulk of the well testing literature is based on the assumption of a radial flow regime. Studies conducted on complex geometries, such as multilayered with or without crossflow and various wellbore and boundary conditions, have focused primarily on the main frame of a radial flow system. The case of linear flow has been emphasized mainly for fracture-controlled flow regime. Recently, the pressure behavior in a long and narrow reservoir was reviewed.2 Spherical flow has received very sporadic attention in the literature.3–5 Each of these flow regimes has its own distinct flow equation. The solution to the flow equation in the absence of wellbore effects results in a straight line on a plot of pressure vs. some function of time. The straight line is obtained for radial flow on a p vs. log ?t, for linear flow on p vs. ?t, and for spherical case on p vs. 1/?t. Selection of the proper flow system depends on what is known about the particular reservoir. For tests conducted during the development stages of a field, such a selection may be possible. The real difficulty is during the exploratory phase, when field data are too few to support a given model strongly. The question addressed here is whether the formation of a straight line on a given pressure vs. time plot is indicative of the corresponding flow regime. The answer would have been easy if the straight line plots were unique. Evidence shows that pressure vs. time data for a given system may result in pseudostraight lines on two or more characteristic plots. A pseudostraight line is defined here as a trend of data points resembling a straight line on a pressure vs. time plot with no physical condition justifying such a case. Experimentation With Theoretical Plots Consider a set of pressure vs. time data where p=f(t) results in a straight line on given plot. The entire set or a portion of the same set may result in a pseudostraight line on other plots. Figs. 2 through 7 show the results of experimentation with these plots. Each case starts with an assumed condition, and the graphical representation on other scales are presented.

Hydraulic fracturing is a technique that increases the efficiency of a production well for a wide range of low to high permeability reservoirs. Many analytical and semianalytical solutions have been presented to model the performance of hydraulic fractured wells. Most models that are developed to investigate the effect of hydraulic fractures on the performance of a well only consider flow from the fracture to wellbore and neglect the direct flow through the matrix to the wellbore. These models consider the linear flow around the fracture, and ignore the radial flow and pressure drop due to interaction between different flow regimes. Neglect of this pressure drop due to flow convergence, is satisfactory only for low permeability formations, such as shale gas and tight oil reservoirs. This pressure drop between the linear and radial flow regimes around the wellbore and hydraulic fracture can contribute to significant inaccuracy in the existing models, particularly in the case of the medium to high reservoir permeability (10 mD and above). This paper presents a new semianalytical approach to determine the simultaneous fluid flow from the matrix and fracture to the wellbore. The concept of the electrical resistance based on the conservation of electrical current and Ohm's law are applied to use the superposition of rate from the fracture and the matrix to the wellbore. Although this method can be applied to transient flow, this paper focuses on the single phase pseudo steady state flow of a vertical well intersecting a vertical fracture with the finite conductivity. This work models the flow convergence pressure drop due to the interaction between linear flow that occurs around the fracture and radial flow in the matrix around the wellbore. Further, a solution for partially communicating fracture with the wellbore is presented as well. In the literature, this form of partial completion pressure drop or skin has been solved for radial flow through the matrix to the wellbore, but this paper presents the pressure drop due to partial completion that opens to a narrow rectangular communication to wellbore which would control the well performance and the contribution of fracture rate. The results clearly demonstrate that the radial flow contributes significantly when reservoir permeability is medium to high. In low permeability reservoirs, linear flow is substantially larger than radial flow and interaction between flow regimes that causes flow convergence pressure drop is negligible. Another important conclusion is the contribution of the hydraulic fracture can be substantially restricted by different flow resistances inside the fracture and the matrix. This paper estimates properly the performance of a hydraulic fractured well and predicts the relative contribution of the fracture and the matrix to the total flow rate in the presence of the additional pressure drops due to different skins as flow resistances around or inside of the fracture, the matrix, and the wellbore.

In this paper, a physico-mathematical model is presented for forecasting gas condensate reservoir performance in multiphase radial and linear flow systems using analytical and semi-analytical models. The proposed methodology is based on the three phase black-oil formulation, incorporating capillary pressure effect in fluid PVT properties in linear and radial flow regimes under constant bottomhole pressure (BHP) and constant flow rate well conditions. The proposed analytical methodology is developed by reducing a system of governing partial differential equations (obtained by rewriting the black-oil mathematical formulation using the Boltzmann transformation) to a system of ordinary differential equations and hence solved using an adaptive step-size Runge-Kutta integration technique coupled with the shooting method without the need to linearize the system of differential equations. Simultaneously, the proposed physico-mathematical model forecasts reservoir pressure profile and saturation behavior in linear and radial multiphase flow systems using three phase relative permeability data and gas condensate PVT data without the need for pressure-saturation or producing gas-oil ratio data inputs into the model. To validate the proposed semi-analytical solution for multiphase-constant gas flow radial systems above the dewpoint pressure, analytical solutions were compared to the line-source solution.

Modern welltest analysis and interpretation techniques are based on match between actual reservoir pressure response and analytical models. In most well and reservoir configurations the analytical techniques are sufficient. However, recent technology advances in drilling and completion, and reservoir heterogeneity detected by modern pressure gauge have identified complex well and reservoir configurations where existing analytical well test models are not adequate for retrieving reservoir properties. This paper presents case studies where a new flow regime was indicated in two hydrocarbon reservoirs when the two wells were tested. Log-log plot of pressure derivative versus time is called diagnostic plot in welltest analysis. Special slope values of the derivative curve are usually used for identification of reservoir and boundary models. These slopes include 0-slope, ¼-slope, ½-slope, and unity slope, etc. However, in many cases the derivative curves do not exhibit slopes of these special values, and it can be assured that the non-special slopes reflect certain flow patterns in the reservoirs. One type of these reservoirs has been observed to be thick reservoirs with either bottom or down-dip water drive. The slopes of the pressure derivative curve for this type of reservoirs are normally below ½ and not equal to ¼. A slope of as low as 0.2 has been observed in a gas reservoir. This paper demonstrates that these low slopes can be attributed to a new flow regime namely Linearly Supported Radial Flow (LSRF). The LSRF may exist in the drainage area of a vertical well where a radial (normally horizontal) flow prevails in a high permeability layer and a linear (normally vertical) flow into the high permeability layer dominates in a low permeability layer. The LSRF may also exist in the drainage area of a horizontal well after pseudo radial flow in the high permeability layer is reached. The linear flow in the low permeability layer may be supported by an aquifer. Analyses using a numerical welltest simulator support this LSRF theory.

Polymer flooding with visco-elastic polymers is an EOR technique improving both macro and microscopic recovery of oil. Its efficiency can be greatly limited by mechanical and chemical degradation of polymers. When injected in the reservoir, the early few centimeters travelled through the rock are crucial for determining the degradation undergone (degradation being defined as the irreversible loss of viscosity). Our aim is is to establish predictive laws for the degradation of polymer solutions flowing through porous media and for the associated flow thickening which can mobility reduction curves of polymer solutions injected or re-injected through sintered ceramic cores of length varying between 1 and 8 mm, we develop a model for predicting mobility reduction and degradation at any length of porous medium, any flux. The model is built by considering that a single injection at flux J on a core having a length NL0 is equivalent to N successive injections at flux J on a piece of the core of length L0. In linear fow, it is found that degradation increases sharply for the first few millimeters and then tends toward a quasi steady state value after a critical length Lc which decreases for increasing fluxes. This model is then transposed to radial flow. Similarly, there exists a critical distance Dc at which degradation reaches a steady state value. Dc is an increasing function of the injection well radius Rw and tends towards Lc at high Rw since radial flow becomes nearly linear. Results obtained with the model are then discussed for predicting precisely on which distance degradation will be experienced and for determining if degradation experiments performed in linear flow in the lab are representative of radial flow around a real polymer injector. This study is a first in injecting polymer solutions through cores as short as 1 mm and in predicting mobility reduction and degradation in both linear and radial flow profiles.

Summary This paper presents results from a comprehensive investigation of the pressure transient behavior of horizontal wells with single or multiple vertical fractures. The approach used can handle fractures with radial and linear inflow to the well, with radial inflow in transverse fractures and linear inflow in longitudinal fractures. Fractures following the wellbore with communication to the well only at the center, i.e., with radial inflow, can also be handled, with these and the tranverse fractures having a circular outer boundary (truncated to the formation if necessary). The longitudinal (rectangular) fractures are assumed to have the full length perforated. Intervals between fractures are assumed not perforated. Most of the paper is devoted to discussions of flow periods exhibited by single- and multifractured horizontal wells under various ideal conditions. Identifying these are important since the special flow periods provide data that can be analyzed by conventional methods. At least four fundamental flow periods can be exhibited by horizontal wells with a tranverse or longitudinal fracture. For a tranverse fracture, or a radial fracture following the well, the periods are fracture radial, radial-linear, formation linear and pseudoradial for fractures fully or nearly confined to the formation. For longitudinal fractures the early flow periods are fracture linear and bilinear. For longer transverse fractures one can also have fracture linear and bilinear flow periods preceded by fracture radial flow. Generally, the fracture radial or fracture linear flow period occurs at a time too early to be of practical use. In any case, due to the transition periods, observing more than two of the fundamental periods in real data is not likely. For highly conductive fractures the early transient behavior is likely to be dominated by formation linear flow, while for poorly conductive fractures this flow period can be absent with the early transient behavior instead dominated by radial-linear or bilinear flow during several log cycles, if not masked by wellbore storage effects. Assuming no boundaries, the pseudoradial flow period will be reached eventually independent of fracture and formation parameters. For all the four fundamental flow periods, conventional straight-line analyses based on semilog, t or t4 plots can be used to determine fracture and formation properties,. During the early flow phase, horizontal wells with single or multiple fractures will experience the same flow periods. However, unless the individual fractures are far shorter than the distance between neighboring fractures, interference will occur before pseudoradial flow is exhibited around each fracture. Before interference occurs the individual fractures drain independent parts of the reservoir and are appropriately analyzed by assuming a single fracture and dividing the total flow rate by the number of fractures. For a multifractured horizontal well, a compound-formation linear flow period may also occur, with linear flow towards the well (as seen from above) dominating the pressure transient behavior. Eventually, provided no flow barriers are encountered, pseudoradial flow will also develop for a multifractured horizontal well. During both the compound-formation linear flow period and the pseudoradial flow period, the full flow rate must be used in the analysis of transient pressure data.

Introduction The objective of this paper is to demonstrate methods of testing and predicting the behavior of very tight gas wells that must be tested under nonideal conditions and that result in data that does not conform to the ideal radial flow concepts. Isochronal testing using constant production rates and bottom hole pressure guages is well understood by most engineers. Interpretation of radial flow isochronal data to obtain the gas well performance when it reaches pseudo steady state flow is also well defined. However, it appears that the flow of gas from a very tight reservoir with a "large" artificial fracture at the well has not been treated in a practical manner. It will be shown that such a well tends to flow under linear unsteady state infinite acting conditions for relatively short periods of time. Then the well gradually changes to a radial flow geometry. An understanding of these flow conditions can lead to an approximate prediction of the gas well behavior with the accuracy depending upon the length of the flow tests and the accuracy of the "guesstimate" of the drainage area of the well. The treatment of the subject is based on a flow test of a gas well producing through the annulus while water production is being pumped through the tubing. Only surface pressures were measured during the flow tests. CONSTANT RATE DRAWDOWN AND ISOCHRONAL TEST THEORY Very tight low permeability reservoirs are generally completed by hydraulically fracturing the well during completion. A long vertical fracture and very low permeabilities permit the well to exhibit linear flow characteristics for very short periods of time. This is demonstrated in Fig. 1. The very low permeability means that the disturbances in the reservoir caused by initiating production will move at a relatively slow rate through the reservoir. Since the effect of the disturbance will move outwardly from the long fracture it means that except for the relatively small amount of the reservoir near the ends of the fracture the flow will be linear. Of course the longer the fracture is the less will the flow into the ends of the fracture cause the overall behavior to deviate from a linear flow geometry. As the affected volume of the reservoir increases with the production time, the fixed length of the fracture becomes smaller in relationship to the affected volume of the reservoir until substantially radial flow will exist throughout most of the drainage area. Thus, for small producing times, t, we would expect the pressure behavior of a well being produced at a constant rate to be governed by an equation for the constant rate infinite acting linear flow behavior in a reservoir.

Summary Horizontal wells with hydraulic fractures in tight oil reservoirs show producing-gas/oil-ratio (GOR) behavior that is very different from conventional, higher-permeability reservoirs. This paper explains the reasons for the observed behavior by use of reservoir simulation, with field examples from the STACK and SCOOP plays of the Anadarko Basin in central Oklahoma. A framework for interpreting observed GOR behavior in tight black-oil reservoirs is modeled after the following stages in a well's history. Some stages may not be visible because of the degree of undersaturation, flowing-bottomhole-pressure schedule, finite-conductivity fractures, and duration of the transient-flow period. Stage 1: Early GOR is constant at the initial solution GOR (Rsi) while bottomhole flowing pressure is above the bubblepoint. Stage 2: A rise in GOR as bottomhole flowing pressure declines to less than the bubblepoint. Stage 3: The transient GOR “plateau”, which is characteristic of transient linear flow. Stage 4: A continuous rise in GOR during boundary-dominated flow. Fundamental differences between linear and radial flow, which cause the dependence of GOR on flowing bottomhole pressure, are explained by use of simulation. During transient linear flow, the GOR response to changes in flowing bottomhole pressure is independent of permeability for infinite-conductivity fractures, but not for finite-conductivity fractures. Several practical observations are made. Knowing Rsi and the transient-GOR-plateau level in an area can help one interpret where a well is in its GOR history. Rate-transient-analysis (RTA) diagnostic plots are altered by rising GOR, and sometimes show an early unit slope. During boundary-dominated flow, GOR is more a function of cumulative production than of time; wells with closer fracture spacing have a faster GOR rise with time, but also recover oil more quickly. If compound linear flow develops, GOR can decline late in the well life. The Meramec and Woodford formations in STACK can be history matched without invoking a suppressed bubblepoint caused by pore-proximity effects. The critical gas saturation in the Meramec appears to be in the range of 0–5%. Technical contributions include a framework for interpreting GOR behavior over well life; the effect of changing bottomhole flowing pressure on GOR; the effect of fracture spacing, conductivity, and half-length on GOR; and the effect of GOR on RTA diagnostic plots.

Due to population growth, the city of Gitega in the central part of Burundi is lacking drinking water. Therefore, the national urban water supply company decided to expand the Nyanzari wellfield by drilling additional wells.Two additional wells were drilled to 80 m (F7.2) and 85 m (F8bis) depths. Step tests followed by 72-hours aquifer tests were performed in each well. Results indicate bilinear flow followed by linear flow and radial flow in F7.2. No reaction was observed in observation wells. Fracture-matrix transmissivity was estimated at 3 · 10−4 m2/s. In the case of F8bis, linear flow in an infinite flow fracture followed by radial flow was visible. Reaction was measured in observation wells. Transmissivity was estimated at 3.3 · 10−3 m2/s.Both wells lie no more than 300 m apart, but no evidence of interference between them was depicted during the tests. It appears that two independent fracture systems prevail in the wellfield.

Nearly all commercial hydraulic fracture design models are based on the assumption that a single fracture is initiated and propagated identically and symmetrically about the wellbore, i.e., the fracture growth and proppant transport occurs symmetrically with respect to the well. However, asymmetrical fractures have been observed in hundreds of hydraulic fracturing treatments and reported to be a more realistic outcome of hydraulic fracturing. The asymmetry ratio (length of short fracture wing divided by length of long wing) influenced the production rate adversely. In the worst case, the production rate could be reduced to that of an unfractured well. Several authors observed asymmetrically propagated hydraulic fractures in which one wing could be ten times longer than the other. Most pressure transient analysis techniques of hydraulically fractured wells assume the fracture is symmetric about the well axis for the sake of simplicity in developing mathematical solution. This study extends the work by Rodriguez to evaluate fracture asymmetry of finite-conductivity fracture wells producing at a constant-rate. The analysis presented by Rodriguez only involves the slopes of the straight lines that characterize the bilinear, linear and radial flow from the conventional Cartesian and semilog plots of pressure drop versus time. This study also uses the Tiab’s direct synthesis (TDS) technique to analyze the linear and bilinear flow regimes in order to find the asymmetry factor of the fractured well. With the fracture conductivity estimated from the bilinear flow region, dimensionless fracture conductivity and the asymmetry ratio are calculated. A technique for estimating the fracture asymmetry ratio from a graph is presented. An equation relating the asymmetry ratio and dimensionless fracture conductivity is also presented. This equation assumes that the linear and/or bilinear flow regime is observed. However, using the TDS technique, the asymmetry ratio can be estimated even in the absence of bilinear or linear flow period. It is concluded that the relative position of the well in the fracture, i.e., the asymmetry condition, is an important consideration for the fracture characterization. A log-log plot of pressure derivative can be used to estimate the fracture asymmetry in a well intersected with a finite-conductivity asymmetric fracture. The analysis using pressure derivative plot does not necessarily require the radial flow period data to calculate the asymmetric factor.

Pressure transient analysis of multi-stage fractured horizontal wells in boxed reservoirs

Diagnostic fracture injection test (DFIT) is a widely used tool to derive key reservoir properties for unconventional reservoirs. This paper proposes a novel and simplified approach to estimate the reservoir transmissibility/permeability from DFIT closure data at linear flow, and without the need for radial flow. The work was implemented in multiple tight sand formation wells. Results yielded an estimate of transmissibility/permeability, and optimize DFIT post-injection monitoring time. The proposed approach incorporates Closure Analysis and After Closure Analysis (ACA) results from previous DFIT tests to derive a correlation for estimating formation permeability. The approach begins by estimating injected fluid leak-off efficiency through the application of the G-function, followed by utilizing ACA to obtain reservoir transmissibility and pore pressure. The concept is built on fluid diffusivity mechanisms. During fracture closure, the fluid leak off mechanism into the formation is governed by the magnitude of Instantaneous Shut-in Pressure (ISIP), until closure pressure is reached. After closure, fluid diffusivity is influenced by another pressure mechanism that is the excess pressure as it diffuses into the formation and approach the reservoir pore pressure. Finally, the fluid efficiency from Closure Analysis is considered as a formation transmissibility index, which is then compiled with the actual transmissibility estimated from ACA to develop the prediction correlation. In this study, the approach was applied in multiple wells where DIFT was concluded before reaching the radial flow. Additionally, the built correlation was used to evaluate the transmissibility in other wells where only closure analysis was available. The correlation developed between the fluid leak-off efficiency and reservoir transmissibility from ACA showed an exponential trend with high accuracy, with a Coefficient of Determination higher than 95%. The result of the correlation was linked to well performance using productivity index as a proxy, yielding accurate result, indicating the critical role formation transmissibility has on fluid deliverability. Applying the productivity index and the predicted formation transmissibility from the correlation matched with high accuracy which validates the methodology. For extremely tight reservoirs, radial flow might be reached after several days, weeks, or months of monitoring pressure decline. The proposed approach saves significant DFIT post-injection time required to observe radial flow. Also, it can be used as validation tool for closure pressure picking where in some case the closure estimation utilizing G-function is selective.

Usually, carbonate acidizing is studied by conducting linear coreflooding experiments in which a hydrochloric acid (HCl) solution is injected into small cylindrical core plugs, such as 1.5×6 in. (diameter×length) plugs. Results from these conventional experiments have provided extensive information on acidizing and wormholing mechanisms, but under conditions of essentially 1D flow along the axis of the plug. Meanwhile, field acidizing scenarios dictate radial (divergent) acid flow conditions around the openhole wellbore, and these conditions influence wormholing aspects such as initiation, branching, and death, in a way that cannot be simulated in linear coreflooding. In this study, we analyzed the results of large-scale radial acid injection experiments to advance understanding and characterization of wormholes created during matrix acidizing treatment. We analyzed the results of high-energy X-ray CT scans for three 20×16×16 in. block samples of Indiana limestone from our recent radial acidizing experiments with HCl. CT scans were done for complete samples, and 3D images of internal dissolution patterns were built. Each 3D image consists of submillimeter-size voxels to capture fine details of individual wormholes. The obtained 3D images of acidized blocks allow us to observe from various angles the details of the wormholes obtained in the three experiments, which demonstrated wide pore-volume-to- breakthrough (PVBT) range with three different injection rates. Also, variation of the CT number reveals the presence of depositional layers in all block samples, and the obtained CT images were used to interpret the effect that rock layers might have on wormhole penetration at different injection rates. Further, the built voxel models were used to calculate the radial distributions of dissolved rock volume, which otherwise are not obvious for such complex branched structures as wormholes. We observed how varied experimental conditions affected those distributions. The radial distributions were found very similar across the samples, which suggested the way to detect the effective wormhole penetration depth. Radial acidizing experiments represent more closely the real conditions of wellbore acidizing; however, only a few radial acidizing experiments have been published to date. In this study, we enriched the results of our recent radial acidizing tests with high-resolution 3D CT images of the created wormholes which are quite rare considering the size of the acidized blocks. In the absence of field techniques to observe the wormholes downhole, CT images of the radially acidized laboratory samples provide valuable information about the appearance of wormholes, as well as quantitative data to validate models of wormhole growth and detection. Particularly, analysis of the obtained images showed how wormhole density responds to changing experimental conditions.

In this work, we challenge the common understanding that mechanical degradation takes place at the rock surface or within the first few mm. The effect of core length on mechanical degradation of synthetic EOR polymers was investigated. We constructed a novel experimental set-up for studying mechanical degradation at different flow rates as a function of distances travelled. The set-up enabled us to evaluate degradation in serial mounted core segments of 3, 5, 8 and 13 cm individually or combined. By recycling we could also evaluate degradation at effective distances up to 20 m. By low rate reinjecting of polymers previously degraded at higher rates, we simulated the effect of radial flow on degradation. Experiments were performed with two different polymers (high molecular weight HPAM and low molecular weight ATBS) in two different brines (0.5% NaCl and synthetic seawater). In linear flow at high shear rates, we observed a decline in degradation rate with distance travelled, but a plateau was not observed. Even after 20 m there was still some degradation taking place. The molecular weight (MW) of the degraded polymer could be matched with a power law dependency, MWD ~L-x, where x for the HPAM was 0.07 and x for ATBS was 0.03. We conclude that in linear flow, the mechanical degradation depends on the core length. However, in radial flow where the velocity decreases by length, the mechanical degradation reaches equilibrium with no further degradation deeper into the formation. For the experiments where we evaluated degradation over large distances at high shear rates, we observed a decline in degradation rate with distance travelled, but we could not conclude that we reached a plateau. Even after 20 m there is still some degradation taking place. It is important to consider this knowledge when interpreting core scale experiments. However, the observed degradation is associated with high-pressure gradients, in the order of 100 bar/meter, which at field scale is not realistic. We confirmed previous findings; degradation depends on salinity and molecular weight. Results show that in all experiments with significant degradation, most of the degradation takes place in the first core segment. Moreover, the higher the shear rate and degradation, the higher is the fraction of degradation that occurs in the first core segment.