High-pressure steady-state flow tests on gas condensates are needed to determine relative permeabilities and their dependence on capillary number. Such experiments require large quantities of reservoir fluids. Other laboratory challenges using reservoir fluids include H2S content and high temperatures.
This paper presents a method that has been used successfully to create synthetic hydrocarbon mixtures that closely mimic reservoir fluid PVT, viscosity and IFT behavior at relevant reservoir pressures. The synthetic mixtures typically consist of 3-4 hydrocarbon compounds, and are readily created in the laboratory in large quantities.
The selection of a synthetic mixture starts with a known description of reservoir fluid PVT properties, from laboratory measurements and/or EOS modeling. Typical PVT include constant composition and constant volume depletion data, viscosities, and gas-oil interfacial tensions (IFT).
The procedure for creating an appropriate synthetic fluid that mimics the reservoir fluid PVT behavior is selection of 3-4 available hydrocarbon compounds, always consisting of methane, at least one light intermediate (C2 to C10), and at least one heavy compound (most often Diphenylmethane DPH-C1). An automated selection process has been developed. We used the SRK EOS with zero BIPs (binary interaction parameters) to describe phase and volumetric behavior of the synthetic fluid system.
With a given group of selected compounds, the amount of each compound is determined by regression to minimize the mismatch between synthetic fluid PVT and reservoir fluid PVT. The synthetic mixture component slate that gives the best match is then chosen from the many possible combinations.
This method has been used for some twenty reservoir gas condensates during the past 15 years. In this paper we illustrate the method for some twelve "public" reservoir gas condensates ranging from lean- to rich fluids, with some containing significant H2S and CO2 content.
The accuracy of synthetic fluid mixtures to mimic actual reservoir gas condensate behavior is surprisingly good. Laboratory applications of the methods presented in this paper have been made without experimental difficulties. In general, the modeled synthetic fluid PVT behavior predicted by an EOS are quite close to the measured laboratory PVT of the synthetic fluids.
The paper provides, for the first time, documentation that 3-4 component synthetic mixtures can be used to represent reservoir gas condensate fluids covering a wide range of composition and PVT behavior.
Yield and buckling are independent of hydrostatic pressure. On the other hand, leak in a threaded connection depends on hydrostatic pressure, and hence leak resistance is a function of connector location in the string. It also means that von Mises stress alone is insufficient to characterize connection leak. Like pipe body yield and buckling, a simple consistent failure theory based on principles of mechanics is proposed for leak in threaded connections. Also, the buckling fictitious force is reformulated as a non-fictitious expression to clearly show independence of hydrostatic pressure. Two leak constants, thread modulus and makeup leak resistance, are introduced and evaluated with simple example cases. To quantify results, a 7″ LTC connection is modeled with the new leak criterion, and results demonstrate that the connection can withstand differential pressures higher than the published ratings because of hydrostatic pressure. A new connection safety factor is defined, and a leak line and a leak circle are developed for graphical purposes to quickly identify critical loads for leak.
Economic development of unconventional reservoirs heavily relies on hydraulic fracturing of horizontal wells in multi-well pads. The application of this technology poses the challenge of determining optimum well spacing. For this reason, well interference analyses have recently gained increased attention in the industry. The objective of this study is to present an analytical well interference model that is aimed to diagnose interwell communication between multistage-fractured horizontal wells (MFHW) in liquid-rich shales in a dual-well system via fracture overlapping or fracture "hits". The mathematical model is based on the application of the trilinear flow model to two parallel MFHW connected through the inner fracture tips. This situation is represented mathematically using a semipermeable boundary condition. This condition features a constant α, called the well interference coefficient, which allows history-matching the analytical model with pressure-transient data.
This paper evaluates three viscoelastic phenomena in high molecular weight polymers (24-28 M Daltons) used for EOR applications based on core flooding experiments. First, we evaluate the impact of semi-harsh conditions (salinity, hardness, and temperature). Second, we investigate the impact of polymer degradation (pipe flow and sandface flow) on viscoelastic properties during polymer flooding. Finally, we propose a threefold approach for understanding these polymer viscoelastic properties by characterizing elongational, rotational, and oscillatory behavior.
For comparison, polymer solutions were prepared in a typical seawater brine (34 g/L and hardness: R+=0.13) and a typical German field reservoir brine (51 g/L and Hardness: R+=0.26). For experimental evaluation, core flooding experiments in conjunction with rheological, oscillatory, and elongational measurements were performed at room temperature (22°C) and a defined reservoir temperature (55°C). Effluents from core flooding experiments were analyzed to evaluate the changes in viscoelastic properties taking place at the sandface of the reservoir. Capillary tube (CT) injection was performed to simulate mechanical degradation occurring in flow lines. These approaches were used to study the influence of mechanical degradation on polymer viscoelasticity.
The polymer solution with deionized water displayed stronger viscoelastic properties, while the same polymer with both brines showed notable loss in viscoelastic properties, specifically at the higher temperature and with hard brine. Pressure drop analysis against interstitial velocity confirmed Newtonian, shear thinning, and thickening dominated flow, as already reported by researchers. Comparing core flood pressure drop data with eVROC pressure data allowed us to determine the turbulence-dominated excessive pressure drop in porous media. In addition, mechanical degradation caused by core flood experiments and CT injection revealed a reduction in elastic-dominated flow using various approaches. Finally, polymer solutions under reservoir harsh conditions (divalent ions, high temperature, and more TDS) resulted in a significant reduction in elastic behavior for all measurements.
Compared to previous studies which mainly focused on viscous properties, this study provides a microscale understanding of changes in polymer elastic properties while flowing through porous media depending on reservoir semi-harsh conditions. Confirmation of the existence of turbulence dominated excessive pressure drop in porous media will help understand pore-scale mechanisms in reservoir engineering.
In this paper we propose a proxy model based seismic history matching (SHM), and apply it to time-lapse (4D) seismic data from a Norwegian Sea field. A stable proxy model is developed for generating 4D seismic attributes by using only the original baseline seismic data and dynamic pressure and saturation predictions from reservoir flow simulation. This method (
In this study we firstly perform a check on the validity and accuracy of the proxy approach following the methodology of (
Giant reservoirs such as Lula (Santos Oil Basin, Brazil) and Ghawar (Saudi Arabia) have high permeability intervals, known as super-k zones, associated with thin layers. Modeling these small-scale flow features in large-scale simulation models is complex. Current methods are limited by high computational costs or simplifications that mismatch the representation of these features in simulation grid blocks. This work has two purposes: (1) present an upscaling workflow to integrate highly laminated or inter-bedded reservoirs with thin, highly permeable layers in reservoir simulations through a combination of (a) an explicit modeling of super-k layers using Parsons (1966) formula and (b) dualmedium flow models, and (2) compare this method with two conventional upscaling approaches, available in commercial software. We use the benchmark model UNISIM-II-R, a fine single-porosity grid based on field information from the Brazilian Pre-salt and Ghawar oil fields, as the reference solution to compare the upscaling matching between the three methods. We compare; oil recovery, water cut, average reservoir pressure, waterfront, and the time consumption for simulation. Our proposed parsons dual-medium (PDP) methodology achieved better upscaling matches with the reference model and had minimal time consumption when compared with the representation of super-k layers through an implicit matrix modelling by single porosity flow models (IMP) and through the explicit representation of super-k zones in the fracture system of dual-medium flow models (DFNDP).
He, Kai (Multi-Chem—A Halliburton Service) | Xu, Liang (Multi-Chem—A Halliburton Service) | Lord, Paul (Multi-Chem—A Halliburton Service) | Kenzhekhanov, Shaken (Colorado School of Mines) | Lozano, Martin (Colorado School of Mines) | Yin, Xiaolong (Colorado School of Mines) | Neeves, Keith (Colorado School of Mines) | Huang, Tao (China University of Petroleum)
As infill drilling practices become more widely used, operators have observed an increase in well interference or "bashing" in various shale plays in which the production of mature wells has been significantly impaired by new infilling wells. Notably, some wells have experienced a production decrease of approximately 80% as a result of bashing. One possible explanation is the occurrence of hydraulic communication between the old and new wells, as they are most likely connected by the newly created or natural fractures. However, the mechanisms in which hydraulic communication influences production have not been fundamentally studied.
Current technologies, such as pressure-transient analysis or production data mining, do not explicitly provide a physical understanding of the bashing phenomena. In this study, "Rock-on-a-Chip" (ROC) devices were used to investigate hydraulic fracturing fluid invasion and flowback processes. A homogeneous porous network based on the Voronoi tessellation method was patterned on a ROC device. To simulate one aspect of well interference (the impact of an offset well's fracturing fluid entering an existing well's fracture network), two fluid invasion-flowback cycles were performed. It was hypothesized that if the fracturing fluid injected through the new infill enters the fracture networks of existing wells, fracturing fluid would again be forced into the matrix, inflicting damage to the fracture-matrix interface and impairing production.
Test results revealed that water saturations in the ROC after the second flowback were higher than those after the first invasion-flowback cycle, suggesting that the second invasion-flowback cycle could indeed damage the matrix and reduce the relative permeability of the oil. Additionally, surfactant clearly improved the displacement efficiencies in the matrix and, therefore, has the potential to reduce the damage incurred by the second invasion-flowback cycle. The benefit of surfactant has been observed from field results from the Wolfcamp shale, where it was discovered that the EURs of wells bashed by surfactant-stimulated offset wells were higher than those bashed by non-surfactant-stimulated offset wells. This study shows that fracturing fluid from offset wells can, in fact, damage the productivity of existing wells through connected fractures. In addition, surfactant, when properly selected, can potentially be used to reduce the damage, or even repair previous damage, caused by well bashing.
Hou, Tengfei (China University of Petroleum, CUPB) | Zhang, Shicheng (China University of Petroleum, CUPB) | Li, Dong (China University of Petroleum, CUPB) | Ma, Xinfang (China University of Petroleum, CUPB)
Uniform proppant distribution in multiple perforation clusters plays a crucial role on sufficiently propping fractures conductivity in hydraulic fracturing. These propped fractures and their effectiveness is critically influenced by the in situ stress in the formation. As great uncertainty exists in uneven propped fracture, this paper examines the impact of proppant distribution and fracture conductivity variation on the gas productivity for shale gas reservoirs, by developing a reservoir simulation model.
In this paper, numerical reservoir simulation, which involves application of a constantly decreasing permeability to the propped fracture, are used to model the uneven proppant distribution and geomechanics effect. The decrease of permeability, along from the wellbore toward the tip, is simulated using an exponential approach, as well as a linear approach. Moreover, Effects of gas desorption and stress-dependent fracture conductivity are taken into account in this model. Sensitivity analysis is carried out on critical parameters to quantify the key parameters affecting gas productivity between uniform and nonuniform proppant distribution. The degree of non-uniform proppant distribution is also investigated and divided into four types of proppant distribution scenarios.
The following conclusions can be obtained based on the simulation results. A big difference on well performance between the case of linear and exponential permeability degradation is observed. The pressure distribution comparison shows higher pressure drops in the exponentially decreasing permeability case, which results in a lower gas production. Reservoir permeability plays a critical role in cumulative gas production, no matter in case of permeability exponentially degrading or linear degrading, followed by fracture half-length, primary fracture conductivity, Fracture complexity, permeability anisotropy. Furthermore, the effect of uneven proppant distribution between different clusters can significantly reduce the gas recovery, especially in low proppant concentration and small fracture conductivity.
The model presented in this paper takes the uneven proppant distribution and geomechanics effect into consideration and shows good agreement with real field production. This paper can demonstrate its own merits on the optimization of hydraulic fracturing treatments, and provide a better understanding of the effect of proppant distribution on well performance.
Transient well testing is one of the most critical components of reservoir evaluation due to its impact on a project's key economic parameters such as reserves and producibility. A conventional cased hole well test involves casing off the well, installing process equipment, completing the well perforating, flowing the well to surface and flaring the produced fluids. While the data acquired from conventional well tests is very useful; a large number of wells are not tested due to time, cost and regulatory constraints. In such situations with no well test, operators are obliged to take important decisions from a relatively small amount of reservoir information and hence take risks associated with subsurface uncertainties. To help reduce the development risks, a new pipe conveyed testing tool referred as Formation Testing While Tripping (FTWT) was developed. The new testing tool integrates a number of innovations allowing pumping large fluid volumes at higher rates with extended testing time and improved well noise control. This is done by circulating the produced fluids out of the wellbore during pumping out formation fluids. The new hardware can be combined with wireline sampling and downhole fluid analysis modules allowing to achieve overall well testing objectives; including collecting pressure transient data, real time fluid typing and capturing cleaner and larger volume fluid samples, while increasing the radius of investigation for better characterization of any reservoir heterogeneities compared to conventional wireline formation testing techniques.
In this paper, we introduce the new testing technique, which has recently been utilized in the Norwegian sector of the North Sea and offshore Canada. In one well, following the FTWT surveys, Drill Stem Tests (DST) were also conducted for comparison. The field examples and comparison with DST's indicated that the new method can provide valuable reservoir information while also showing its current limitations.
Yong, Li (Research Institute of Petroleum Exploration and Development, PetroChina) | Changbing, Tian (Research Institute of Petroleum Exploration and Development, PetroChina) | Baozhu, Li (Research Institute of Petroleum Exploration and Development, PetroChina) | Yixiang, Zhu (Research Institute of Petroleum Exploration and Development, PetroChina) | Benbiao, Song (Research Institute of Petroleum Exploration and Development, PetroChina)
For reservoir development study, there are a lot of uncertainties in different research aspects. But if these uncertainties are ignored, reservoir performance could be much worse than expected because of wrong development options possibly selected and applied. Therefore, uncertainty analysis should be addressed during reservoir development study, and uncertainty parameters should be analyzed and their impact should be evaluated in order to reduce the corresponding risks. The paper proposes that uncertainty analysis should run through the whole study process of reservoir development plan.
Based on the reservoir development stage and reservoir geological features, all related uncertainty factors are identified. And the uncertainty range of each factor are determined with upside, expected and downside values or models. Then all factors are embedded into the static and dynamic models, and the uncertainty impact on reservoir performance are quantitatively evaluated based on the upside, expected and downside dynamic models respectively. After that, uncertainty parameters are ranked into differernt groups.
Take one large multi-layered sandstone oilfield in Middle East for example, uncertainty analysis methods are illustrated. The large sandstone reservoir in Middle East is at its primary depletion development stage with only 5% recovery factor currently, and waterflooding is urgert. Firstly, key uncertainty parameters are determined, which can be mainly classified into two categoriesgeological model and dynamic model. Then according to the characteristic of this reservoir and uncertainties understanding of geological study, 3 static models with same probability are built. After that, uncertainties understanding of dynamic analysis are included into static models, and 3 dynamic models representing Upside, Expected and Downside models are generated in order to fully characterize all the uncertainties. So development options and development schemes optimization can be studied based on the 3 models in order to determine the uncertainties of water flooding performance. Finally the induced risks of each main uncertainty parameter are quantitatively evaluated, and corresponding treatments are proposed.
This paper offers the methodology and a case study on uncertainty analysis and management within the waterflooding development for a large multi-layered sandstone reservoir, and the results are valuable for the following development options decision making. It also provides a reference for uncertainty management of similar reservoir.