Siv Marie Åsen, UiS, IRIS, and The National IOR Centre of Norway; Arne Stavland and Daniel Strand, IRIS; and Aksel Hiorth, UiS, IRIS, and The National IOR Centre of Norway Summary In this work, we examine the common understanding that mechanical degradation of polymers takes place at the rock surface or within the first few millimeters of the rock. The effect of core length on mechanical degradation of synthetic enhanced-oil-recovery (EOR) polymers was investigated. We constructed a novel experimental setup for studying mechanical degradation at different flow velocities as a function of distances traveled. The setup 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. Experiments were performed with two different polymers [high-molecular-weight (MW) hydrolyzed polyacrylamide (HPAM) and low-MW acrylamide tertiary butyl sulfonic acid (ATBS)] in two different brines [0.5% NaCl and synthetic seawater (SSW)]. In the linear flow at high shear rates, we observed a decline in degradation rate with distance traveled. Even after 20 m, some degradation occurred. However, the observed degradation was associated with high pressure gradients of 100 bar/m, which at field scale is not realistic. It is possible that oxidative degradation played a significant role during our experiments, where the polymer was cycled many times through a core.
In this paper, we use a combination of acoustic impedance and production data for history matching the full Norne Field. The purpose of the paper is to illustrate a robust and flexible work flow for assisted history matching of large data sets. We apply an iterative ensemble-based smoother, and the traditional approach for assisted history matching is extended to include updates of additional parameters representing rock clay content, which has a significant effect on seismic data. Further, for seismic data it is a challenge to properly specify the measurement noise, because the noise level and spatial correlation between measurement noise are unknown. For this purpose, we apply a method based on image denoising for estimating the spatially correlated (colored) noise level in the data. For the best possible evaluation of the workflow performance, all data are synthetically generated in this study. We assimilate production data and seismic data sequentially. First, the production data are assimilated using traditional distance-based localization, and the resulting ensemble of reservoir models is then used when assimilating seismic data. This procedure is suitable for real field applications, because production data are usually available before seismic data. If both production data and seismic data are assimilated simultaneously, the high number of seismic data might dominate the overall history-matching performance.
The noise estimation for seismic data involves transforming the observations to a discrete wavelet domain. However, the resulting data do not have a clear spatial position, and the traditional distance-based localization schemes used to avoid spurious correlations and underestimated uncertainty (because of limited ensemble size), are not possible to apply. Instead, we use a localization scheme that is based on correlations between observations and parameters that does not rely on physical position for model variables or data. This method automatically adapts to each observation and iteration.
The results show that we reduce data mismatch for both production and seismic data, and that the use of seismic data reduces estimation errors for porosity, permeability, and net-to-gross ratio (NTG). Such improvements can provide useful information for reservoir management and planning for additional drainage strategies.
Recently, there has been a drive towards a risk-based approach to plug & abandonment (P&A) design. To apply a risk-based approach for decision-making, i.e. to decide if a P&A design is acceptable or not, risk acceptance criteria have to be established and be approved by authorities. This paper presents the core of a risk-based approach, and then present three alternative risk acceptance criteria based on leakage risk of permanently plugged and abandoned wells.
The core elements of the risk-based approach for evaluation of the containment performance in permanently plugged and abandoned wells consist of estimating probability of leakage and associated leakage rates for any proposed P&A design. These will then have to be used to evaluate the acceptability of the design, by comparing them to some defined acceptance criteria. Different principles can be followed to define such criteria, such as being consistent by accepting risk levels which have been considered acceptable in other situations, environmental survivability or considering the cost-benefit to optimize the allocation of funds.
The approach and principles used are described and applied in the context of P&A design. Based on the specification of an actual gas producing well that was permanently plugged and abandoned on the Norwegian Continental Shelf (NCS), a synthetic case study is established. Simulations are carried out to provide estimations of the core elements of the risk-based approach, i.e. leakage rate and probability of the leakage, for the synthetic case. Three examples of risk acceptance criteria are then presented and discussed. The estimations derived from simulations for the synthetic case study are used to exemplify the strengths and weaknesses of the three acceptance criteria.
Ensemble-based methods are among the state-of-the-art history matching algorithms. In practice, they often suffer from ensemble collapse, a phenomenon that deteriorates history matching performance. To prevent ensemble collapse, it is customary to equip an ensemble history matching algorithm with a certain localization scheme. Conventional localization methods use distances between physical locations of model variables and observations to modify the degree of observations' influence on model updates. Distance- based localization methods work well in many problems, but they also suffer from some long-standing issues, including, for instance, the dependence on the presence of physical locations of both model variables and observations, the challenges in dealing with nonlocal and time-lapse observations, and the non-adaptivity to handle different types of model variables. To enhance the applicability of localization to various history matching problems, we propose to adopt an adaptive localization scheme that exploits the correlations between model variables and observations for localization. We elaborate how correlation-based adaptive localization can mitigate or overcome the noticed issues arising in conventional distance-based localization.
To demonstrate the efficacy of correlation-based adaptive localization, we apply it to history-match the real production data of the full Norne field model using an iterative ensemble smoother (iES), and compare the history matching results to those obtained by using the same iES but with distance-based localization. Our study indicates that, in comparison to distance-based localization, correlation- based localization not only achieves close or better performance in terms of data mismatch, but also is more convenient to implement and use in practical history matching problems. As a result, the proposed correlation-based localization scheme may serve as a viable alternative to conventional distance-based localization.
In this work we present a systematic geosteering workflow that automatically integrates a priori information and the real-time measurements for updating of geomodel with uncertainties, and uses the latest model predictions in a Decision Support System (DSS). The DSS supports geosteering decisions by evaluating production potential versus drilling and completion risks.
In our workflow, the uncertainty in the geological interpretation around the well is represented via multiple realizations of the geology. The realizations are updated using EnKF (Ensemble Kalman Filter) in real-time when new LWD measurements become available, providing a modified prediction of the geology ahead of the bit. For every geosteering decision, the most recent representation of the geological uncertainty is used as input for the DSS. It suggests steering correction or stopping, considering complete well trajectories ahead-of-the-bit against the always updated representation of key uncertainties. The optimized well trajectories and the uncertainties are presented to the users of the DSS via a GUI. This interface enables interactive adjustment of decision criteria and constraints, which are applied in a matter of seconds using advanced dynamic programming algorithms yielding consistently updated decision suggestions.
To illustrate the benefits of the DSS, we consider synthetic cases for which we demonstrate the model updating and the decision recommendations. The DSS is particularly advantageous for unbiased high-quality decision making when navigating in complex reservoirs with several potential targets and significant interpretation uncertainty. The initial results demonstrate statistically optimal landing and navigating of the well in such a complex reservoir. Furthermore, the capability to adjust and re-weight the objectives provides the geosteering team with the ability to change the selected trade-offs between the objectives as they drill. Under challenging conditions, model-based results as input to a decision process that is traditionally much based on human intuition and judgement is expected to yield superior decisions.
The novel DSS offers a new paradigm for geosteering where the geosteering experts control the input to the DSS by choosing decision criteria. At the same time, the DSS identifies the optimal decisions through multi-objective optimization under uncertainty. It bridges the gap between developments in formation evaluation and reservoir mapping on one side, and automation of the drilling process on the other. Hence, the approach creates value based on the existing instrumentation and technology.
Plug & abandonment (P&A) regulations on the Norwegian continental shelf are largely prescriptive, since the same requirements are applied irrespective of well conditions. A risk-based approach on the other hand, is a well-specific approach to assess the quality of a given plug and abandonment design solution. Probability of leakage and consequence, in the form of leakage rates to the environment, should be quantified for permanently plugged and abandoned wells in a risk-based approach.
To address the consequence aspect of a risk-based approach, a tool for quantitative leakage assessment is essentially needed. This should cover all leakage pathways for reservoir fluids to the environment, i.e. leakage through the well and leakage outside the well through the surrounding formation. The integrity of the cement barrier could be weakened as a result of e.g. poor slurry design, tensile stresses and shrinkage, creating leakage pathways through the bulk cement, cracks and micro-annuli along cement interfaces. As for the surrounding formation, geological features such as faults and fractures, as well as the sealing ability of the cap rock, are important factors to consider from a barrier integrity perspective. Fractures or faults might intersect a permeable formation at a shallow depth, potentially enabling reservoir fluids to migrate into the wellbore or to the seabed.
The authors have developed a leakage assessment simulator, to quantify leakage rates for permanently plugged and abandoned wells. The structure and models incorporated in the preliminary version of the simulator, covering only leakage pathways through the wellbore, was previously presented in SPE-185890-MS.
The current study builds on the previous paper by also accounting for leakage scenarios outside the well through the surrounding formation. The structure of the leakage assessment simulator is also presented in this paper. Additionally, features that may significantly reduce leakage rates, such as barite plug are addressed. A synthetic case is presented where leakage rate is estimated for two scenarios, a) leakage through the well only and b) leakage through the well and the surrounding formation.
While drilling horizontal sections, an operator experienced tool-joint wear, which in extreme cases was one-sided, necessitating the replacement of many drill-pipes to minimize the risk of drill-string failure. Since there were no observable signs of the wearing process, the strategy has been to trip midway through the section to inspect the pipes. With the goal to drill the section in one run, an investigation of the root causes of the abnormal wear has been started.
To check whether some hidden signal patterns could help detecting under which circumstances the tool-joints were worn out, a play back of some of those drilling operations has been undertaken with specific attention to whether transient hydraulic and mechanical models could help differentiate abnormal measurement signatures. In parallel, it has been investigated with computational fluid dynamic (CFD) software whether synchronous whirl of tool-joints would generate a specific pressure signature that could easily be recognized. As the asymmetrical wear of the tool-joints indicated the presence of synchronous whirl, it has also been analyzed how side forces were distributed along the drill-string.
Neither the playback nor the CFD analyses pointed to conditions leading to tool-joint wear. On the other hand, the side force analysis showed that because of extensive directional work linked to geosteering, reaction forces on the tool-joints were very unevenly distributed on the first 500m of drill-string behind the BHA. However, the distribution of the positions of the high and low side forces changed radically for different bit positions. Numerous hard-stringers were encountered while drilling which suggests that the irregular distributions of side-forces on the string have been maintained for longer periods of time. As a result, these conditions have allowed drill-string whirl to be kept sufficiently steady with the consequence of severely damaging the tool-joints.
Mathematical modelling of the drill-string behavior can help determining the critical rotational speed as a function of the weight on bit by which whirl can take place. With this information at hand, it is then possible to give concrete advice to the drilling team on which drilling parameters to use to minimize the risk of tool-joint wear.
The present article reviews the technology trends in cement job evaluation using logging tools and considers the main advantages and concerns associated with each technology. The technologies covered include recent acoustic tools, temperature logging, noise logging, resistivity logs, oxygen activation logs, X-Ray measurements, Gamma-Gamma density measurements, Neutron-Neutron logging, and fiberoptic measurements. Technology trends in cement logging tools suggest that acoustic measurements such as pulse-echo and flexural measurements may be the leading techniques for cement job evaluation into the next decade. Although temperature logging tools are available and have potential for well integrity evaluation their application for primary cement job evaluation remains limited to top of cement location and qualitative evaluations. Various noise logging tools are commercially available to detect leaks but their application is limited to investigating well integrity issues and not primary cement job verification. Among the technologies and techniques reviewed, theoretically Neutron-Neutron and X-ray measurements may have the potential to be future technologies for cement job evaluation. Neutron-neutron logging tools have the advantage of being already available whereas X-ray logging tools are not yet developed for cement job evaluation. Besides tool availability, power supply, tool size, and data analysis are challenges to be solved when implementing an X-ray based technique.
Step Rate Test (SRT) is commonly used to estimate formation parting (or fracture opening) pressure for stimulated wells. SRTs may also focus on changes of well performance at different rates / pressures that is of special interest for stress-sensitive reservoirs such as fractured carbonates. Installation of permanent downhole gauges (PDG) and running SRTs on injection wells at the Ekofisk field gave a chance to improve the understanding of reservoir and well performance. Analysis of these SRTs also resulted in further development of SRT interpretation techniques.
An approach to SRT interpretation, combining analytical pressure-rate (
Special attention was paid to the uniqueness of SRT interpretation using suggested approach. Reaching infinite acting radial flow (IARF) regime at each step of a test provided unique parameter estimates as shown by example of a stimulated slanted injector. Being too far from IARF at end of each step will make the interpretations more uncertain. Different sets of changing parameters estimated from SRT interpretation could provide satisfactory match in numerical runs as was illustrated by example of a horizontal injector with multiple induced fractures. Comparison of interpretation results for different wells integrating additional field data is a possible way to reduce this uncertainty.
Finally, some hints to designing, conducting and interpreting SRTs of different types of wells in fractured carbonate fields are given, using Ekofisk field experience.
Reservoir rock and crude oil samples are usually exposed to oxygen during storage and in laboratory experiments. Ferrous ions (Fe2+) on mineral surfaces and in brines can be oxidized to ferric ions (Fe3+). Rock samples can also be contaminated with Fe3+, e.g. from muds. The objective for the study has been to investigate the effects of Fe2+ oxidation and cation bridging by Fe2+ and Fe3+ on wettability.
Oxidation of Fe2+ to Fe3+ was first investigated by aging formation water (FW) solutions at reservoir temperature. The effect of Fe3+ on wettability was then studied for the clay mineral glauconite. The wettability was characterized using a flotation method that relies on the affinity of the minerals to either the brine or oil phase. Flooding experiments were carried out in native and restored reservoir cores using FW, sea water (SW) and low salinity water (LSW) as injection waters. The element composition of effluent samples was determined. Geochemical simulations were carried out to further investigate the interactions of brine with the mineral and rock in the flotation tests and core flooding experiments.
During aging of FW samples for 2 days, 46% of Fe2+ (50ppm) was oxidized to Fe3+. FW containing 50ppm Fe3+ gave less water-wet glauconite clay than FW without Fe3+. The flotation method showed that Fe3+ increased the concentration of oil-wet glauconite by 366% and 67% for two different FW/STO systems. The effluent Fe concentration was very low during injection of FW and SW to native reservoir cores, but a Fe peak was observed in LSW floods. No Fe was detected in the effluents during injection of FW, SW and LSW to the restored reservoir cores.
Geochemical simulations showed that 50ppm Fe3+ was not affecting the concentration of multivalent cations onto clay surfaces. The alteration of wettability of glauconite to less water-wet was most likely due to precipitation of surface active iron-minerals on glauconite surfaces. According to the simulations, the solubility of Fe3+ was very low in all brines (FW, SW and LSW) injected to the reservoir cores. The observed Fe-peak during injection of LSW to the native reservoir core plugs can therefore not be explained by the simulation results. The solubility of Fe3+ may have been higher than simulated because of complexes between Fe3+ and carboxylic acids.
The study has shown that geochemical simulations can be helpful in interpretation of different types of experiments. Similar method can also be used to evaluate the potential for oxidation of Fe2+ and thereby the risk for precipitation of surface active Fe-minerals. These can give wettability conditions not representative for the actual oil reservoir.