We present a CT coreflood study of foam flow with two representative oils: hexadecane C16 (benign to foam) and a mixture of 80 wt% C16 and 20 wt% oleic acid (OA) (very harmful to foam). The purpose is to understand the transient dynamics of foam, both generated in-situ and pre-generated, as a function of oil saturation and type. Foam dynamics with oil (generation and propagation) are quantified through sectional pressure-drop measurements. Dual-energy CT imaging monitors phase saturation distributions during the corefloods. With C16, injection with and without pre-generation of foam exhibits similar transient behavior: strong foam moves quickly from upstream to downstream and creates an oil bank. In contrast, with 20 wt% OA, pre-generation of foam gives very different results from co-injection, suggesting that harmful oils affect foam generation and propagation differently. Without pre-generation, initial strong-foam generation is very difficult even at residual oil saturation about 0.1; the generation finally starts from the outlet (a likely result of the capillary-end effect). This strong-foam state propagates backwards against flow and very slowly. The cause of backward propagation is unclear yet. However, pre-generated foam shows two stages of propagation, both from the inlet to outlet. First, weak foam displaces most of the oil, followed by a propagation of stronger foam at lower oil saturation. Implicit-texture foam models for enhanced oil recovery cannot distinguish the different results between the two types of foam injection with very harmful oils. This is because these models do not distinguish between pre-generation and co-injection of gas and surfactant solution.
Ugueto, Gustavo A. (Shell Exploration and Production) | Todea, Felix (Shell Canada Limited) | Daredia, Talib (Shell Canada Limited) | Wojtaszek, Magdalena (Shell Global Solutions International) | Huckabee, Paul T. (Shell Exploration and Production) | Reynolds, Alan (Shell Exploration and Production) | Laing, Carson (OptaSense) | Chavarria, J. Andres (OptaSense)
The use of Distributed Acoustic Sensing for Strain Fronts (DAS-SF) is gaining popularity as one of the tools to help characterize the geometries of hydraulic fracs and to assess the far-field efficiencies of stimulation operations in Unconventional Reservoirs. These strain fronts are caused by deformation of the rock during hydraulic fracture stimulation (HFS) which produces a characteristic strain signature measurable by interrogating a glass fiber in wells instrumented with a fiber optic (FO) cable cemented behind casing. This DAS application was first developed by Shell and OptaSense from datasets acquired in the Groundbirch Montney in Canada. In this paper we show examples of DAS-SF in wells stimulated for a variety of completion systems: plug-and-perforating (PnP), open hole packer sleeves (OHPS), as well as, data from a well completed via both ball-activated cemented single point entry sleeves (Ba-cSPES) and coil-tubing activated cemented single point entry sleeves (CTa-cSPES). By measuring the strain fronts during stimulation from nearby offset wells, it was observed that most stimulated stages produced far-field strain gradient responses in the monitor well. When mapped in space, the strain responses were found to agree with and confirm the dominant planar fracture geometry proposed for the Montney, with hydraulic fractures propagating in a direction perpendicular to the minimum stress. However; several unexpected and inconsistent off-azimuth events were also observed during the offset well stimulations in which the strain fronts were detected at locations already stimulated by previous stages. Through further integration and the analysis of multiple data sources, it was discovered that these strain events corresponded with stage isolation defects in the stimulated well, leading to "re-stimulation" of prior fracs and inefficient resource development. The strain front monitoring in the Montney has provided greater confidence in the planar fracture geometry hypothesis for this formation. The high resolution frac geometry information provided by DAS-SF away from the wellbore in the far-field has also enabled us to improve stage offsetting and well azimuth strategies. In addition, identifying the re-stimulation and loss of resource access that occurs with poor stage isolation also shows opportunities for improvement in future completion programs. This in turn, should allow us to optimize operational decisions to more effectively access the intended resource volumes. These datasets show how monitoring high-resolution deformation via FO combined with the integration of other data can provide high confidence insights about stimulation efficiency, frac geometry and well construction defects not available via other means.
The identification of the fluid fill history is a necessity for the development strategy of any field, in particular in the Middle East where tectonic history is often reported to affect fluid distribution and contacts in many fields. The fluid fill concept for a low permeability carbonate field has been re-evaluated and modified from a tilted contact interpretation with imbibition of the deepest unit to a field-wide flat contact and primary drainage saturation distribution. The oil volumes in the reservoir under study are sensitive to minor changes in the structure and fluid fill due to the relatively low structural dip and low permeability transitional nature of the reservoir. The paper highlights the importance of removing preconceptions in data analysis and ensuring consistency on interpretations between different available data sources. It also demonstrates how data quality could completely change the fluid fill concept.
The three main reservoir units of the Lower Shuaiba A, Lower Shuaiba B and Kharaib have been charged from two oil migration events. Structural changes post the first primary drainage are revealed by regional seismic images of the shallower horizons. Due to the rock low permeability, the water saturations are above irreducible value and the whole interval is in the "transition zone". Kharaib unit was believed to be imbibed by the aquifer after charge and was not developed. Three possible fluid fill scenarios were investigated: a) tilted contact due to structural changes post-charge, b) imbibition of the deeper interval, c) primary drainage with field-wide flat contact related to the second pulse of charge. Each scenario impacts the development of the three units positively or negatively. Water saturation logs vs. True Vertical Depth plots were the main diagnostic tool used to rule out fluid fill scenarios. The plots were used to recognise lateral changes of the saturation profile and investigate imbibition signatures. Production data were also used to cross check the expected fluid fill scenario. The resistivity tools’ types and mud resistivities were examined.
Mondal, Somnath (Shell International Exploration and Production) | Ugueto, Gustavo (Shell Exploration and Production Company) | Huckabee, Paul (Shell Exploration and Production Company) | Wojtaszek, Magdalena (Shell Global Solutions International) | Daredia, Talib (Shell Canada Limited) | Vitthal, Sanjay (Shell Exploration and Production Company) | Nasse, David (Shell Exploration and Production Company) | Todea, Felix (Shell Canada Limited)
In recent years, Step-Down Tests (SDTs) are being increasingly used for diagnosing completions effectiveness in plug-and-perf (PnP) fracturing in unconventional wells. SDT is primarily used to quantify pressure drop related to perforation friction, near-wellbore tortuosity (NWBT), and to estimate perforation efficiency (PE) i.e. the fraction of active perforations at the end of a hydraulic fracturing treatment of a stage. In the industry, perforation efficiency is generally considered to be the yardstick for evolving limited entry designs and perforating strategies. In a typical SDT, the injection flowrate is reduced in 3 to 4 abrupt steps, each of duration long enough for the rate and pressure to stabilize, to enable interpretation of the rate and pressure response. However, simple as it may appear to be, the interpretation of SDT as a stand-alone diagnostic test has several assumptions and inherent non-uniqueness that are often ignored. This paper presents integrated data, diagnostics, and analysis from multiple completion types across multiple basins that demonstrates the methodology and uncertainties associated with SDT analysis.
In this paper, the SDT methodology was applied to 2 wells with different completion styles, and the interpretation was supplemented with fiber optics and bottomhole pressure gauges (BHPG). In the first well, SDTs were conducted on multiple stages of a cemented single-point entry (CSPE) sleeve completion that had well-defined, erosion-resistant openings to reduce uncertainties in the “perforation” pressure drop solution. In the second example, SDTs were conducted on multiple stages of a PnP well. Each PnP stage had two SDTs – one was conducted post pad but before proppant and another at the end of entire treatment, both with clean fluids.
The authors have highlighted the uncertainties with traditional SDTs and the need for integration with additional diagnostics. The analysis shows that the exponent of flowrate commonly used to quantify pressure drop associated with NWBT is largely uncertain. It also demonstrates the non-uniqueness of the SDT interpretation, and that a range of perforation diameters and a / the number of active perforations can match the SDT unless constrained with fiber optics data and perforation imaging data. The interpretation with constant perforation diameter is found to generally overestimate the PE. The SDTs before and after proppant slurry placement, if correctly interpreted, show an increase in perforation diameter with a reduction in PE post proppant placement. This paper demonstrates that without constraints on either eroded perforation diameter or on a / the number of active perforations, the interpretation of SDT is non-unique.
Distributed Acoustic Sensing (DAS) and Distributed Temperature Sensing (DTS) analysis also illustrates the variable and non-unique tortuosity, and/or complex stimulation domain architecture, in the near-wellbore region. It is therefore recommended that SDTs be interpreted with consideration of the inherent complexities and uncertainties, and preferably supplemented either with perforation imaging or DAS and DTS data for more accurate analysis.
To summarize, accurate interpretation of SDTs requires an interdisciplinary diagnostics approach, which is critical for optimization of limited entry designs.
Martins, Ana (Nederlandse Aardolie Maatschappij) | Marino, Marco (Nederlandse Aardolie Maatschappij) | Kerem, Murat (Shell Global Solutions International) | Guzman, Manuel (Shell Global Solutions International)
This paper presents the first comparison between two different injection methods for foam assisted gas lift. Useful information for operators and technology developers are also provided concerning chemical selection, testing, and deployment of this hybrid artificial lift technology in the field.
The trials have been conducted in a gas lifted oil well with severe slugging and water cut above 50% (selection criteria as per SPE-184217-MS). The surfactant was delivered through a dedicated capillary injection string during the first trial, and the effects of surfactant concentration and depth of injection were evaluated. During the second trial, the surfactant was injected into the gas lift stream at the surface. Different surfactants were utilised for both trials based on stability concerns and method of injection.
Both trialled injection methods successfully stabilized the well flow, terminating severe slugging while increasing the drawdown and delivering an increase in gross production of circa 200%. These results, together with the downhole pressure data collected during the first trial, confirm that the surfactant starts foaming only at the depth where the lift gas enters the tubing. Injecting surfactant into the lift gas stream required higher concentrations than using a dedicated injection string, difference attributable to the slightly different chemistry, but even at those higher concentrations an anti-foamer injection was not required.
Concerning the response time, the well responded in 30 to 60 minutes with capillary string injection, while 6 to 12 hours were required for injection into the lift gas stream. This suggests that the surfactant probably moves slowly down on the annulus walls as a liquid film rather than travelling in droplets dispersed in the gas phase. Based on the outcome of the two trials, it is concluded that the injection via the lift gas stream is as effective as capillary string injection, at a fraction of the initial costs, with lower maintenance requirements, while still allowing access to the well.
Gao, Guohua (Shell Global Solutions (US)) | Vink, Jeroen C. (Shell Global Solutions International) | Chen, Chaohui (Shell International Exploration and Production) | Araujo, Mariela (Shell Global Solutions (US)) | Ramirez, Benjamin A. (Shell International Exploration and Production) | Jennings, James W. (Shell International Exploration and Production) | El Khamra, Yaakoub (Shell Global Solutions (US)) | Ita, Joel (Shell Global Solutions (US))
Uncertainty quantification of production forecasts is crucially important for business planning of hydrocarbon-field developments. This is still a very challenging task, especially when subsurface uncertainties must be conditioned to production data. Many different approaches have been proposed, each with their strengths and weaknesses. In this work, we develop a robust uncertainty-quantification work flow by seamless integration of a distributed-Gauss-Newton (GN) (DGN) optimization method with a Gaussian mixture model (GMM) and parallelized sampling algorithms. Results are compared with those obtained from other approaches.
Multiple local maximum-a-posteriori (MAP) estimates are determined with the local-search DGN optimization method. A GMM is constructed to approximate the posterior probability-density function (PDF) by reusing simulation results generated during the DGN minimization process. The traditional acceptance/rejection (AR) algorithm is parallelized and applied to improve the quality of GMM samples by rejecting unqualified samples. AR-GMM samples are independent, identically distributed samples that can be directly used for uncertainty quantification of model parameters and production forecasts.
The proposed method is first validated with 1D nonlinear synthetic problems with multiple MAP points. The AR-GMM samples are better than the original GMM samples. The method is then tested with a synthetic history-matching problem using the SPE01 reservoir model (Odeh 1981; Islam and Sepehrnoori 2013) with eight uncertain parameters. The proposed method generates conditional samples that are better than or equivalent to those generated by other methods, such as Markov-chain Monte Carlo (MCMC) and global-search DGN combined with the randomized-maximum-likelihood (RML) approach, but have a much lower computational cost (by a factor of five to 100). Finally, it is applied to a real-field reservoir model with synthetic data, with 235 uncertain parameters. AGMM with 27 Gaussian components is constructed to approximate the actual posterior PDF. There are 105 AR-GMM samples accepted from the 1,000 original GMM samples, and they are used to quantify the uncertainty of production forecasts. The proposed method is further validated by the fact that production forecasts for all AR-GMM samples are quite consistent with the production data observed after the history-matching period.
The newly proposed approach for history matching and uncertainty quantification is quite efficient and robust. The DGN optimization method can efficiently identify multiple local MAP points in parallel. The GMM yields proposal candidates with sufficiently high acceptance ratios for the AR algorithm. Parallelization makes the AR algorithm much more efficient, which further enhances the efficiency of the integrated work flow.
Building realistic and reliable subsurface models requires detailed knowledge of both the rock and fluids involved. While the hydrocarbon volume estimation has a profound impact on the viability of a development, next to the saturation height models and free fluid levels the hydraulic communication and permeability have a significant role as well. Compartmentalization could change the field development plan: e.g. increase the well count, necessitate significant change to the well profiles (e.g. extended range drilling), require complex and expensive completion strategy.
When in different parts of the same field different free fluid levels are identified, leading to different fluid contacts for the same rock quality, the lateral hydraulic communication at the field level can be challenged. This aspect is of importance since the hydrocarbon volume distribution has drastic impact on total hydrocarbon recovery. At the same time building and initializing a model based on different free water level positions across the field, zero capillary pressure, is challenging.
Perched water contacts are the result of water entrapment during the hydrocarbon migration that could lead to variability in free fluid levels across a field. The fundamental controls that lead to the perched contacts formation are studied and shown to be the rock quality and relative permeability. Counter-intuitively, the perching effect is not going to feature in poor quality rocks with sub-milli Darcy permeability – the effects would be visible only for a considerable barrier height, with Free Water Level to barrier height of tensto hundred meters.
In addition, realistic heterogeneous models are studied to investigate the heterogeneity effect on perching and on formation pressures. Whilst low permeability is correlated to a wide range of depths where two phases are mobile, the perching controls in high permeability contrast formations are studied.
Using a dynamic modelling route, potential water entrapment occurrence as a result of high permeability contrast is shown, without structural control, i.e. an underlying impermeably zone defining a trap. The main control in such a case is water permeability just as in structurally controlled perching. This work challenges the industry view that model initialization should be performed with buoyancy as an equilibrium driving mechanism. Such a saturation modelling route would lead to discrepancies when compared to using the capillary pressure as a direct input instead of buoyancy.
Ernens, Dennis (Shell Global Solutions International BV and University of Twente) | van Riet, Egbert J. (Shell Global Solutions International) | de Rooij, Matthias B. (University of Twente) | Pasaribu, Henry R. (Shell Global Solutions International) | van Haaften, Willem M. (Shell Global Solutions International) | Schipper, Dirk J. (University of Twente)
D. Ernens, Shell Global Solutions International BV and University of Twente; E. J. van Riet, Shell Global Solutions International; M. B. de Rooij, University of Twente; H. R. Pasaribu and W. M. van Haaften, Shell Global Solutions International; and D. J. Schipper, University of Twente Summary Phosphate-conversion coatings are widely used on (premium) casing connections for protection against corrosion. These coatings provide galling protection in conjunction with lubricant. The friction and wear that occur during makeup and subsequent load cycling strongly influence the sealing performance of the metal/metal seal. An extensive test program was set up to investigate the role of phosphate coatings during makeup and in the subsequent sealing of the metal/metal seal. With pinon-disk, anvil-on-strip, and ring-on-ring tests, the interactions between the substrate, lubricant, and phosphate coating were investigated. A comparison was made between uncoated and coated specimens using base greases and formulated greases: API-modified lubricant and two commercially available yellow dopes. The results indicate a strong influence of the phosphate coating leading to damage-free makeup, low wear, and less dependence on the lubricant for optimal sealing ability. This is attributed to the formation of a hard and smooth dissimilar surface, the ability to adsorb the lubricant, and the generation of a transfer layer on the uncoated countersurface. It is concluded that taking the interaction with phosphates into account could enable lubricants to be tailored for sealing performance, and thus can ease the transition to environmentally friendly rated lubricants. Introduction Phosphate-conversion coatings (Rausch 1990; Narayanan 2005) were initially applied on (premium) casing connections for protection against corrosion during storage. A side effect of the presence of the phosphate coatings was improved galling resistance (Ertas 1992). Phosphate-conversion coatings therefore play an important role in the proper makeup of casing connections and their subsequent sealing performance. The premium connection (Figure 1), and for this paper its metal/metal seal, should be considered as a (tribo)system (Salomon 1974; Czichos and Winer 1978), which is defined as the combination of lubricant (dope), coating, surface finish, and casing-material grade under sliding conditions. The contact conditions are determined by the pin/box interference and the mechanical properties of the pipe material.
Ugueto, Gustavo (Shell Exploration and Production) | Huckabee, Paul (Shell Exploration and Production) | Wojtaszek, Magdalena (Shell Global Solutions International) | Daredia, Talib (Shell Canada Limited) | Reynolds, Alan (Shell Exploration and Production)
It has been widely demonstrated that frac stimulation efficiency and more importantly production, varies significantly between perforation clusters as well as between sleeve entries. Recent trends indicate that many operators are simultaneously increasing the number of perforation clusters or entries while decreasing frac-to-frac spacing. This is done with the expectation that it will lead to more productive wells overall. The purpose of this paper is to investigate some of the aspects that may limit this approach. There are an increasing number of frac diagnostic tools which allow us to get a better understanding of frac placement and production. Unfortunately, there are only few diagnostic tools available today to characterize the near wellbore region (NWR). Fiber Optics (FO) and other downhole measurements can play an important role in providing information about the NWR. In this paper, we share data and examples from wells where the combination of data from Distributed Acoustics Sensing (DAS), Distributed Temperature Sensing (DTS) and downhole gauges is helping us gain insights about this poorly understood region of our unconventional reservoirs. This paper combines DAS, DTS and downhole pressure gauge data to demonstrate the existence of significant near wellbore complexity, both during stimulation and production. We frequently observe changes in DAS signal and pressure during the stimulation of horizontal wells completed via both "Plug and Perf" (PnP) and Cemented Single Point Entry (CSPE) systems. These changes support the existence of significant near-wellbore tortuosity. Furthermore, we show that pressure data from downhole gauges can differ significantly from surface pressure data extrapolated downhole. This can impact the interpretation of Step-Down-Tests, other analytical techniques relying on the surface pressure alone and affecting the calibration of frac models aimed at understanding the NWR. In wells instrumented with a FO cable behind casing, it is possible to use the DTS data during warmback, following stimulation injection to gain insights about frac geometry in the NWR. Such data provides information about the hydraulic frac dimensions created by the stimulation process in both vertical and horizontal wells. During warmback it is easy to distinguish intervals containing hydraulic fractures near the wellbore where the temperature recovery is lagging compared to the unstimulated portions of the well. FO instrumented horizontal wells allow for estimation of the dimensions of the "Frac-Zone" along the wellbore in the NWR where a combination of hydraulically induced longiditunal and vertical transverse fracs exist. Thermal modeling is also presented for selected stages that further support the qualitative interpretation of the DTS. The diagnostics presented help quantify the dimensions of longitudinal and transverse components in horizontal wellbores in the NWR. This paper also highlights the risk of putting perforation clusters or sleeve entries too close to one another. It is clear that the NWR is poorly understood and more information is needed. Understanding the processes that govern the NWR are essential, after all, this is the region where the well and the reservoir interact.
Barnes, Julian R. (Shell Global Solutions International) | van Batenburg, Diederik W. (Shell Global Solutions International) | Faber, M. J. (Shell Global Solutions International) | van Rijn, Carl H. T. (Shell Global Solutions International) | Geib, Sonja (Shell Global Solutions International) | van Kuijk, Sjoerd R. (Shell Global Solutions International) | Perez Regalado, David (Shell Global Solutions International) | King, Tim E. (Shell Global Solutions US) | Doll, Mike J. (Shell Global Solutions US) | Crom, Lori E. (Shell Global Solutions US)
Alkaline/surfactant/polymer (ASP) flooding is an enhanced-oil-recovery (EOR) technique that involves the injection of a solution of surfactant, alkali, and polymer into an oil reservoir to mobilize and produce the remaining oil. There are several pattern-flood pilots in progress or that will soon be executed to evaluate ASP at a scale relevant to commercial-scale application. The quantities of surfactants needed for these pilots and potential future commercial-scale applications are large (hundreds to thousands of tonnes) and necessitate large-scale manufacture using existing processes and plants for the different manufacturing steps. These operate under slightly different process conditions than those used to make the smaller quantity (50 to 400 kg) of the reference blend used to design the formulation in the laboratory. The upscaling of the surfactant production itself is an essential step to enable field-scale implementation of ASP. To ensure and control the quality of the surfactants produced for pilots with Shell interests, a stage-gated quality assurance/quality control (QA/QC) program was designed and executed. The application of the QA/QC process for a high- and a low-active-matter surfactant-blend concentrate (approximately 60% and 20% active, respectively) is used to illustrate the process.
The early definition of the QA/QC program provided a framework with clearly defined stages for upscaling from laboratory- to large-scale production. The definition of analytical and performance-based laboratory experiments with upfront-defined specifications (minimum and maximum values) and repeatability allowed for clear, unambiguous decisions. Correlations between composition and performance that were developed dependent on pilot-scale production were essential to assure the performance of the larger-scale production. Corefloods, used as the ultimate performance check, showed virtually identical performance for pilot-scale prepared surfactants and surfactants from different large-scale batches.
The paper illustrates that consistent industrial-scale production of surfactants for application in chemical EOR (CEOR) is feasible. To ensure the quality of such surfactant requires a detailed QA/QC program. The successful execution of the QA/QC program for the surfactants for the pattern pilots ensures that the produced large-scale surfactant blend performs as the reference blend used to design the formulation.