bluuebunny/crossref_metadata_2025_split huggingface dataset:
Clipper South Field: Fracturing Operations and Production Matching in a Low Permeability, Sandstone Gas Reservoir in the North Sea
Authors: Shaoul Josef , Park Jason , Bakhtiyarov Albert , Fekkai Sofiane , Jeffs Paul , Mandiwall Darrell 
Published: June 2013

Abstract
In order to produce economically viable wells from the Clipper South field, a low permeability gas reservoir in the UK Southern North Sea gas basin, the field was planned to be developed with horizontal, multiple hydraulically fractured wells. Clipper South is a Rotliegend dry gas field, comprising a mix of aeolian, fluvial and sandy sabkha sediments. The field is located approximated 100 km due east of the Theddlethorpe gas terminal in 23.5 m water depth. Reservoir is at 8,200 ft TVDSS, with average porosity 7 % and permeability ranging across the field from 80 μD to 100 μD in the core area. Initial temperature and pressure are 170 °F and 3,900 psi respectively. The field was discovered by well 48/19a-3 in 1983 and appraised by an additional well in 1992; well tests showed minimal flow from perforated intervals pre-fraccing. Given the poor reservoir quality, to sufficiently capture the reserves, development of the field requires five high angle wells with multiple hydraulic fractures in each well.
When drilling the first well unexpected reservoir complexity was encountered; no natural fracture network was seen in appraisal wells but C1 encountered sizable natural fractures and multiple high permeability streaks when drilling with significant gas peaks and associated mud losses. The natural fracture network influenced placement and necessitated alterations to fracture designs compared to planned dimensions. No dedicated stimulation vessel was available for the Clipper South development; a new-build supply-vessel was converted for use by installation of a large capacity frac spread which successfully pumped 8 frac-jobs along a 6,000 ft horizontal reservoir section. Stimulation was completed by the end of June 2012 and the well was brought online August, achieving above target post-stimulation flow rates.
This paper discusses how diagnostic data was incorporated into fraccing designs to produce a successful well; in particular logging data acquisition and pre-frac diagnostic tests, and how multiple injection tests were used to gain information on permeability along the wellbore to aid future reservoir modelling. Challenges encountered during stimulation operations and their implication for fracturing future wells will be discussed, along with methods for stimulation optimization and lessons learned. A summary will be given of the post-frac production analysis using a 3D reservoir simulation model with explicit Modelling of the eight propped fractures.
Building a Simulation Grid for Large Scale Reservoir Simulation
Authors: Al-Saadoon Omar , Hayder M. Ehtesham , Baddourah Majdi 
Published: June 2013

Abstract
Large scale reservoir simulation is essential to understand various flow processes inside the reservoir. With the advent of high performance computing (HPC), it is now possible to simulate models larger than even one billion cells. Because of its cost effectiveness, Linux clusters are very popular for large scale reservoir simulations. Many large clusters have been built by connecting processors via state-of-the-art high speed networks like Infiniband (IB), which can add considerable cost for the hardware. It is possible to connect multiple computer clusters to build a simulation grid, to simulate giant models, which may be difficult to do on a single cluster because of the size limitation. The network connecting clusters should be capable of supporting the needed data transfer rate to avoid performance degradation. Communication and computational load in a simulation depends on various parameters of the model, including size, underlying physics, mathematical formulation, etc. Our focus in this study is to examine HPC architectures, which may be used for large scale reservoir simulation in a cost-effective manner. Our design was made following extensive benchmark studies. We designed the network configuration, which is blocking in design to reduce the cost of hardware associated with the network. Our tests with large models indicate that there is only minor degradation in performance because of the new design, while significantly saving in hardware cost. We followed the Hyperscale design principle in constructing the cluster, eliminating all unnecessary components and keeping only essential ones. In this paper, we present results of our simulation grid and discuss scalability of such simulations. We also discuss benefits of a simulation grid in increasing utilization of hardware resources.
Integration of Production Facilities and Reservoir Simulation for Comparison of Subsea and Conventional Lift Technologies
Authors: Teixeira G. N. , Schiozer D. J. 
Published: June 2013

Abstract
Subsea processing has been considered a potential technology to anticipate and to increment oil production in deep water fields. The key element to achieve this is to increase pressure drawdown by reducing the backpressure imposed by the system. It can be defined as any treatment of the produced fluids performed on the seabed. Among the available technologies, Subsea Gas-Liquid Separation is the most advanced one for deep water applications. The most recommended way to estimate incremental oil recovery and to compare with other artificial lift technologies is through Integrated Production Modeling, which integrates reservoir, production and processing facility models.
The motivation of the present work is the need to quantify the incremental oil recovery achieved through subsea processing and the objective is to evaluate the possible advantages of using subsea gas-liquid separation as the main artificial lift method of a reservoir with similar characteristics observed in the recent discoveries in Brazil, comparing its performance with one of the most traditional lift technologies: gas lift.
The comparison is performed in two case studies. In the first one, a homogeneous reservoir model is used to focus the comparison in the artificial lift technologies. In the second case study, a heterogeneous reservoir model is used to evaluate the performance in a more realistic reservoir.
The results show that reservoir pressure maintenance is a key element to extract all benefits related to this subsea technology. A combination of technology (subsea gas-liquid separation and gas lift) also shows that it is possible to increment the oil production in a mature phase of the field. However, that it is not the same as changing the artificial lift technology. One of the benefits of subsea gas-liquid separation is that it is possible to produce the same oil quantity, compared to gas lift, with a smaller tubing and pipeline diameter.
Understanding the Impact of the Dynamic Environment When Acquiring Formation Pressures Whilst Drilling
Authors: Blanco Yon , Turner Marcus , Paul Scott , Benmansour Amel 
Published: June 2013

Abstract
In the last decade, Formation Pressure While Drilling (FPWD) measurement has developed from an emerging technology to a ubiquitous technology in environments ranging from ultra-deep water to land operations, as it is recognized for its cost efficiency and data quality when applied correctly. In addition to traditional uses similar to those of wireline-conveyed formation testers for reservoir evaluation, specific FPWD applications enabling real-time decision making in the well-construction process, such as drilling optimization and geo-steering, are now heavily utilized.
Many still argue that acquisition via wireline-conveyed methods produce higher quality data for reservoir evaluation, but to compare the measurements acquired by both technologies, it is necessary to understand the physics and dynamics in which both measurements are acquired. While typically the dynamic nature of FPWD data acquisition is seen to be disadvantageous because of mud circulating effects and potentially incomplete mudcake formation, operational practices during acquisition can mitigate these effects and particularly enhance test interpretation. There are unique opportunities for better understanding of test response and formation characteristics that are only available if the data are acquired early in the drilling phase. Complementing these measurements later with wireline data or even a subsequent FPWD pass while pulling out of the hole normally provides very valuable time-lapse information.
During this decade we have learnt that applying the same FPWD procedure for all environments might not obtain data of the highest possible quality because there are many variables to consider from the application to the environment. Formation types, mobilities, compaction, circulation rates, and mud types must be carefully considered during both planning and execution stages. In practice, we encounter reservoirs with variable permeabilities, different lithologies, and mud systems that are not always adequate. Lessons gathered from various environment types and innovative methods of acquiring data will be presented to address the following concerns: Formation damage and time-after-drilling implicationsAt-balance/underbalance conditionsStatic and dynamic superchargingTight and unconsolidated formations
The solutions developed through a decade of global experience and lessons learnt provide to new and existing users detailed insight into how to optimize procedures to deliver high quality data in many environments, whilst avoiding potential issues with the aim of acquiring pressure and mobility measurements as close as possible to a true representation of the formation under evaluation.
Assessing the Non-Uniqueness of the Well Test Interpretation Model Using Deconvolution
Authors: Cumming J. A. , Wooff D. A. , Whittle T. , Crossman R. J. , Gringarten A. C. 
Published: June 2013

Abstract
Uncertainty in well test analysis results from errors in pressure and rate measurements, from uncertainties in basic well and reservoir parameters; from the quality of the match with the interpretation model; and from the non-uniqueness of the interpretation model.
These various uncertainties, except the non-uniqueness of the interpretation model, were examined in SPE 113888. It was concluded that the permeability-product kh is generally known within 15%; the permeability k, within 20% (because of the uncertainty on the thickness h); and the skin effect S, within 8% for high S values and within ±0.5 for low S values. Distances (half-fracture lengths, horizontal well lengths, and distances to reservoir boundaries) are usually known within 25%.
The issue of non-uniqueness of the interpretation model is more complex: not only may there be a multitude of possible models for any one derivative response (the usual inverse problem), but there may be also a multitude of derivative responses, due to the uncertainty inherent in the observed data.
This paper presents a methodology for assessing the derivative response uncertainty using deconvolution. It is shown that the uncertainty depends mainly on the error bounds for initial pressure and flow rates, which yield a range of possible shapes for the deconvolved pressure derivative and therefore different possible interpretation models. In some cases, the non-uniqueness of deconvolution can be reduced using knowledge of the expected model response, for instance from geology or seismic. In the absence of differentiating information, however, alternative interpretation models have to be considered, which may lead to completely different development options.
The methodology is illustrated with three field examples.
Effect of Strong Preformed Particle Gel on Unswept Oil Zones/Areas During Conformance Control Treatments
Authors: Elsharafi Mahmoud O. , Bai Baojun 
Published: June 2013

Abstract
In oil industry, it is important to decrease water production and improve oil sweep efficiency. A newer trend in gel treatments is using preformed particle gel (PPG) to reduce fluid channels through super-high permeability streaks/fractures. The success of a PPG treatment depends primarily on whether or not PPG can selectively penetrate into highly permeable channels or fractures while minimizing penetration into lower permeable, unswept zones/areas. The purpose of this work was to determine what factors influence the damage of strong PPG on low-permeable, unswept zones. A filtration apparatus was designed to determine the possible penetration of PPG into low-permeable sandstone rocks. Filtration curves (the relationship between injection times vs. filtration volume) were obtained, and the permeability of sandstone cores, both before and after PPG treatment, was measured to determine whether or not PPGs reduce the permeability of low-permeable rocks. Daqing (DQ) gel was used as a PPG sample for our filtration experiments. DQ is a strong gel particle with an elastic module of ~6500 Pa at 1% of NaCl (wt%). The particle sizes of the gel ranged from 30 to 120 meshes. Filtration test results showed that 30–80 meshes of DQ did not impair the rocks with the permeability of of 3–25 mD. However, a powder of DQ gel with 100–120 meshes formed a cake on rock’s surface and reduced the core permeability up to 92.93 %. The damage of particle gel on unswept, low-permeable zones/areas was found to be effectively reduced by controlling both the particle size and the concentration of brine that was used to prepare swollen PPG.
Numerical Simulation of CO2 Storage Using the Vertical Equilibrium Approximation
Authors: Adeyinka Adeboye , Pickup Gillian , Olden Peter 
Published: June 2013

Abstract
When CO2 is injected into a saline aquifer for storage purposes, it rises through the brine to form a thin plume underneath a caprock (or under an intermediate shale layer). This is challenging to model, because a fine grid is necessary to resolve the plume and, since aquifers are extensive, many grid cells are required. On the other hand, simulations may be speeded up by using vertical equilibrium (VE) which assumes instantaneous separation of fluids due to gravity.
The focus of this work is to compare VE models with conventional black oil (BOS) and compositional simulations (CS) to determine conditions under which the VE approximation is valid. A simple 2D homogeneous pilot model was tested first. The base case model had 81×1×81 cells, and the refined models had 243×1×243 and 729×1×729 cells. Subsequently, a realistic 3D model representing the Bunter formation in the southern North Sea was used. This type of formation is expected to be used for CO2 storage in the future.
The results from the pilot model showed that the VE model could adequately represent the plume with a coarser grid than the BOS or CS models. For a homogeneous model, the VE approximation is therefore very useful. However, when applying VE to a heterogeneous 3D model, the results must be treated with caution. For the CS model, the areal distribution of the CO2 at the top of the aquifer showed that CO2 had migrated only through the high-permeability cells while the VE model showed evidence of CO2 migration through the high and moderate permeability cells.
The VE model saved processor time and gave reasonable results at low grid resolution. Even though the results may be less accurate for heterogeneous aquifers, the use of VE is important for the extended reservoir simulations needed to generate multiple realizations to capture the uncertainties and their effects on the aquifer-description parameters.
Modeling Net-to-gross in Deepwater Reservoirs
Authors: Chen Jiajie Jeff , Larson Todd 
Published: June 2013

Abstract
Use of Net-to-Gross (NTG) concept in reservoir modeling has been a debate as it involves choice of cutoff, a simplified representation of reality. In-place hydrocarbon volumes highly depend on the cutoff, thus some authors suggest avoiding use of this concept. However, when building a reservoir model, a process involving upscaling the well log curves to the reservoir grid resolution is often needed. This requires the investigators to account for the portion of an active cell that can allow fluid to flow. Thus, when carefully evaluated, the NTG method can be a necessary and acceptable approximation. From outcrop studies we also observe that no turbidite sequences have consisted of 100% net reservoir sands. The variations of net sand percentages depend on the vertical and lateral variations of strata that serve as the building bricks of the overall sequences. Several methods have been tested to model the NTG for various deepwater reservoirs in the Gulf of Mexico (GOM): Calibration of acoustic impedance (AI) curve into NTG from each individual well and propagating the NTG using stochastic method guided by seismically inverted AI and facies distributionScaling Gamma Ray (GR) or shale volume (VSH) curve to NTG by fixing the end members (sand and shale), scaling the curves linearly, and then conducting Sequential Gaussian Simulation to propagate NTG from wells to the reservoir modelUsing VSH cutoff to generate initial NTG for the wells, correlating the NTG with AI, and developing multi-relationships from the NTG-AI space to estimate NTG at the model scale. The multi-relationships serve as a tool for sensitivity test in the reservoir modelUsing total porosity frequency distribution from well logs to separate effective porosity for reservoir sands and un-effective porosity for non-reservoir rocks, then using porosity cutoff to distinguish sand from shale, and upscale the well log curves to model grid resolution to account for NTGEstimating NTG directly from whole cores
Using some case studies, we compared the difference of in-place volumes estimated based on different approaches. The studies show that as long as the assumptions for each method are physically sound, the NTG estimates are consistent. We conclude that the NTG of deepwater reservoir sands and their connectivity are the most important factors controlling total resource distribution and flow capability.
Reservoir Fluid Characterisation from Tests on Tight Formations
Authors: Moffatt Brian , Fawcett Michael , Maurera Jaimar , Bruzco Anna 
Published: June 2013

Abstract
Drill stem testing of low permeability reservoirs is challenging because high pressure drawdown around the wellbore readily lowers fluids below saturation pressure and creates two-phase flow into the wellbore. The fluids produced at surface no longer represent the original reservoir fluid. This paper shows the benefits of a careful methodology of data selection and equation of state (EOS) modeling to validate data used to characterize the reservoir fluid. Cases are examined where standard methods of capturing and characterising the reservoir fluid failed either because of sampling difficulties caused by two-phase flow within the reservoir. The first example is a lean gas condensate where there was a discrepancy between surface and bottom hole sample compositions. By an extended analysis of Gas: Oil ratio (GOR) over all the flow tests and taking a broader perspective of the welltest data, it was demonstrated the surface data were superior to the bottom hole samples. The second study is of a disguised volatile oil which had previously been classified as a rich gas-condensate based on welltest GOR. However, a review of the GOR versus rate and EOS modeling of reservoir saturation pressures gave a consistent indication that the native fluid was not a condensate but a volatile oil. In both examples the methodology of careful data selection followed by consistency of EOS modeling gave interpretations contrary to rule of thumb assumptions and revealed the true reservoir fluid compositions.
Extension of a Simple Model for Vertical Sweep in Foam SAG Displacements
Authors: de Velde Harsenhorst R. M. , Dharma A. S. , Andrianov A. , Rossen W. R. 
Published: June 2013

Abstract
Foam is a promising method to improve sweep in gas-injection enhanced-oil-recovery (EOR) projects. Where well-to-well distances are large, as in offshore applications, the question arises whether foam can prevent gravity segregation over large distances. For such cases, theoretical studies suggest that the best process is to inject one large slug of surfactant followed by one large slug of gas. Shan and Rossen (2004) present a simple model for such a process that provides an initial assessment whether foam can prevent segregation over large distances. They did not extend their calculations to the large distances between wells in some applications, and they treated only the case where vertical permeability kv equals horizontal permeability kh. Here we extend the model to cases of kv &lt; kh. We derive an analytical solution for the limit as kv approaches zero, which could serve as quick first estimate of feasibility for other cases. Surprisingly, the model predicts that gravity segregation is worse as kv decreases; the reason is that with large kv foam pushes gas downward in response to the pressure difference across the titled foam front.
We illustrate use of the model with an example from a North Sea field, where the issue was whether foam could prevent gravity segregation over a distance of several km. The simple model said this was feasible, and more-detailed simulation then confirmed that segregation was insignificant over an inter-well distance of 6 km.