Producers in Texas have claimed an economic victory with their transition to local sands that they once avoided using in horizontal wells due to their low-quality. Driven by a recovery in well completions and increased proppant loading per well, the market for raw fracturing sand is expected to grow by more than 4% annually through 2021, an industry research study says. Permian Basin producer Callon Petroleum is attributing its data-driven approach to a routine completions practice to improved proppant placement and higher oil production. Carbo Ceramics is making big strides in the use of ceramic proppant. Although Saudi Arabia has plenty of sand, it took some ingenuity by Saudi Aramco and Schlumberger to figure out how to use it effectively as proppant.
With high reservoir heterogeneity in terms of permeability and fluid properties, substantial amounts of oil are produced along with water. At water cuts higher than 96–98%, wells become uneconomic and are shut in or undergo water shut-off treatments. For this reason, shutting off water flow through thief zones in flooded reservoirs to prevent it from entering wells is one of the biggest technical challenges in enhancing oil recovery from mature multi-reservoir oil fields.
As the water cut increases, water flow through thief zones must be reduced, along with the amount of water entering the well, to enhance sweep efficiency in lower-permeability portions of the reservoir. A new technology employing polymer dispersed systems (PDS) shuts off formation and injected water flows by increasing flow resistance in thief zones. This process redistributes the energy of the injected water in the reservoir and helps produce oil from unswept zones, thus increasing flooding efficiency and oil recovery. PDSs do not require drastic changes in existing development systems and are employed together with conventional water-flooding methods.
This paper presents studies of basic and modified PDS versions for oil recovery enhancement adapted for conditions existing in the Vyatka area of the Arlan oil field containing poorly continuous reservoirs with lithofacies heterogeneity. This depleted area had a stable, high water cut.
The new method for enhancing water flooding efficiency using polymer dispersed systems presented in the paper selectively increases flow resistance in the thief zones of productive formations with a resulting increase in sweep efficiency.
Tong, Fangchao (Yanchang Petroleum) | Tang, Mingming (Yanchang Petroleum) | Chen, Gang (Yanchang Petroleum) | Wang, Ningbo (Yanchang Petroleum) | Liu, Peng (Schlumberger) | Yan, Gongrui (Schlumberger) | Lin, Wei (Schlumberger)
Drilling horizontal wells in YB gas field in Ordos Basin presents significant challenges due to severe wellbore instabilities problems in drilling through Permian Lower Shihezi and Upper Shanxi formations, where laminated shales overlies with sand and coal seam. In first phase of horizontal wells drilling, most wells encountered severe wellbore instabilities including pack-off, stuck-pipe, over-pull, drilling pipe lost in hole and even side track. Post-well analysis showed that these horizontal wells instabilities mainly occurred in Permian Lower Shihezi and Upper Shanxi formation where most cavings and drilling events (stuck-pipe, over-pull) were observed. In contrast, vertical exploration wells have no such instability issues in same interval. To analyze and understand the mechanism of wellbore instability issue and provide optimal mud weight and better drilling practice to reduce the risk of wellbore instabilities, an anisotropic wellbore stability modeling using Plane-of-Weakness (PoW) failure criterion was carried out in this study. The PoW failure criterion is adopted to compute the onset of rock shear sliding and/or fracture along a weak plane (bedding or fracture) and identify the potential wellbore instability risk in drilling through anisotropic rock formations. The influence of bedding orientation, rock anisotropic elastic and strength properties, and wellbore trajectory on the wellbore stability are all included in the model.
This paper describes the process and workflow of conducting PoW wellbore stability modeling for YB field wellbore drilling. The proposed drilling parameters (stable mud weight) from the modeling and its application and improvement for next wells drilling, are also included. The analysis showed that the laminated shale and coal intervals were very prone to fail when well drilled with deviation between 600 to 850. The stable mud weight computed from PoW for drilling through these intervals is 1.40-1.45 g/cc, where as it is 1.20-1.25 g/cc from conventional isotropy wellbore stability model, which was not enough to keep wellbore stable. Based on results from PoW modeling, drilling mud weight scheme was updated and applied to another 3 horizontal wells planned at nearby location. All these three wells were drilled and completed safely without severe wellbore instability issue. In these wells’ 216mm (8.5 in) section, wellbore instability related non-productive time (NPT) was reduced about 11.5 days per well and section time was reduced about 26 days per well.
This PoW modeling was first time applied in wellbore stability analysis for horizontal well drilling at Ordos Basin and the results are satisfied and encouraged. The insights provided in this paper suggests that, for drilling in other locations with similar instability challenges, PoW modeling will be a better choice to provide solution and recommendation to ensure drilling safely, improve drilling efficiency and reduce drilling costs.
Zhu, Haiyan (Chengdu University of Technology) | Zhao, Ya-Pu (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation) | Feng, Yongcun (Institute of Mechanics, Chinese Academy of Sciences) | Wang, Haowei (Institute of Mechanics, Chinese Academy of Sciences) | Zhang, Liaoyuan (University of Chinese Academy of Sciences) | McLennan, John D. (University of Texas at Austin)
Haiyan Zhu, Chengdu University of Technology, State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, and Institute of Mechanics, Chinese Academy of Sciences; Ya-Pu Zhao, Institute of Mechanics, Chinese Academy of Sciences and University of Chinese Academy of Sciences; Yongcun Feng, University of Texas at Austin; Haowei Wang, Southwest Petroleum University; Liaoyuan Zhang, Sinopec Shengli Oilfield Company; and John D. McLennan, University of Utah Summary Channel fracturing acknowledges that there will be local concentrations of proppant that generate high-conductivity channel networks within a hydraulic fracture. These concentrations of proppant form pillars that maintain aperture. The mechanical properties of these proppant pillars and the reservoir rock are important factors affecting conductivity. In this paper, the nonlinear stress/strain relationship of proppant pillars is first determined using experimental results. A predictive model for fracture width and conductivity is developed when unpropped, highly conductive channels are generated during the stimulation. This model considers the combined effects of pillar and fracture-surface deformation, as well as proppant embedment. The influence of the geomechanical parameters related to the formation and the operational parameters of the stimulation are analyzed using the proposed model. The results of this work indicate the following: 1. Proppant pillars clearly exhibit compaction in response to applied closure stress, and the resulting axial and radial deformation should not be ignored in the prediction of fracture conductivity. Introduction In conventional hydraulic-fracturing treatments, it is presumed that proppant is distributed uniformly in the fracturing fluid and generates a uniform proppant pack in the fracture (left-hand side of Figure 1). The propped fracture serves as a high-conductivity channel facilitating fluid flow from the reservoir to the well. Channel fracturing is a new fracturing concept, and replaces a nominally homogeneous proppant pack in the fracture with a heterogeneous structure containing a network of open channels (Figure 1, right) (Gillard et al. 2010). This channel-like structure is achieved by using fiber-laden fluids or self-aggregating proppant together with a pulsed-pumping strategy. In channel fracturing, the interaction between the proppant and fracture surfaces is a "point" contact, in contrast to the "surface" contact assumed to exist in conventional fracturing.
The oil and gas industry has advanced over time in terms of seismic data acquisition. From conventional data acquisition to full/wide/multi-azimuth broadband data, there is an abundance of subsurface information aimed mainly at enhancing structural resolution, for improved prospect definition. Conventional seismic imaging tends towards the higher amplitude specular/continuous part of the seismic dataset for generating reflection events. During this process amplitudes or energy related to small scale features and faults can be contaminated, therefore in order to capture that information, it is essential to preserve the wavefield while imaging.
Polymer flooding is a mature Enhanced Oil Recovery process which is used worldwide in many large- scale field expansions. Encouraged by these positive results, operators are still looking at applying the process in new fields even in the context of low oil prices and are evaluating its feasibility in more challenging reservoir conditions: high salinity, high hardness and high temperature. Several solutions have been proposed to overcome the limitations of the conventional hydrolyzed polyacrylamide (HPAM) in these types of challenging environments: biopolymers such as xanthan or scleroglucan, associative polymers, or co- or ter-polymers combining acrylamide with monomers such as ATBS or NVP. Each of these solutions has its advantages and disadvantages, which are not always clear for practicing engineers. Moreover, it is always interesting to study past field experience to confront theory with practice. This is what this paper proposes to do.
The paper will first review the limits of conventional HPAM and other polymers that have been proposed for more challenging reservoir conditions. But more than that, it will focus on the field experience with each of these products to establish some practical guidelines for the selection of polymers depending on the reservoir and fluid characteristics.
One first result of this review is that the limits of conventional HPAM may not be as low as usually expected. Biopolymers appear very sensitive to biodegradation and their success in the field has been limited. Associative polymers appear better suited to near-wellbore conformance control than to displacement processes and some of the new co and ter-polymers are currently being field tested with some measure of success. It appears that the main challenge lies with high temperature rather than high salinity; some field projects are currently ongoing in high salinity (200 g/L) and hardness.
The paper will help set the current limits for polymer flooding in terms of temperature, salinity and hardness based on laboratory work and field experience. This will prove a useful guide for practicing engineers looking to pilot polymer injection in challenging reservoir conditions.
Smith, Michael B (NSI Technologies) | Deng, Jia Yao (Premier Oilfield Group) | Sajid, Bilal (National Petroleum Services Company K.S.C.P.) | Mokhtar, Ahmed Anwar Youssef (National Petroleum Services Company K.S.C.P.) | Taramov, Musa (National Petroleum Services Company K.S.C.P.)
The application of acid fracturing techniques to deeply buried carbonate reservoirs is often an attractive option due to acid's ability to penetrate/improve natural fracture production where a gel frac fluid may damage the natural fractures. However, effectiveness of acid can be limited due to depth, temperature, and high in situ stress. The introduction of acid creates surface roughness or asperities that hold the fracture open under reservoir conditions, but all three factors above diminish the applicability of acid etched fractures. Under extreme stress these fractures close unless artificially propped open in some fashion. The advantage of combining the two approaches (acid+proppant) is not only an improvement in the natural fracture conductivity through the acid etching, but also yields a longer lasting conductivity in the main fracture from the emplacement of the proppant.
The idea of adding proppant to an acid fracture stimulation job has a long history but has seldom been used due to a fear (not unfounded) of proppant flowback, and the lack of design tools to quantitatively identify proper candidates. Additionally, models based upon the classic Nierode-Kruk correlations were often over-optimistic in predicting fracture conductivity under high stress conditions, disguising the potential need for combination treatments.
Recent developments in modeling, especially the upscaling of laboratory data to field-scale, make it possible to evaluate the combination of both techniques. The completion design and post-test analysis of two recent acid+proppant stimulation programs in Middle-East carbonate reservoirs is examined. Case 1 was a 10m interval at a depth of 3600m (11,800 ft). Closure stress was 700 bar (10,000 psi). Case 2 was a 35 m thick interval at a depth of 2200 m (7000 ft) with an average porosity of 20% and permeability of > 5 mD as determined from wireline logs. Reservoir temperature/pressure for this case were 120 C (260 F) and 250 bar (3600 psi), with an in-situ closure stress of 350 bar (5100 psi). The formation was characterized by the homogeneous distribution of porosity/permeability.
Ulyanov, Vladimir (Gazprom Neft) | Kuchurin, Alexey (Gazpromneft STC) | Kibirev, Evgeny (Gazpromneft STC) | Gryzunov, Andrey (Gazpromneft-Orenburg) | Bak, Viktor (SIANT) | Rymarenko, Konstantin (Siberian Federal University) | Nukhaev, Marat (Siberian Federal University) | Dadakin, Nikita (Siberian Federal University)
The gas-lift operation is widely internationally used in the oil production. At present, this production method is used at the Orenburg oil and gas condensate field as one of its options--a natural-pressure gas-lift well operation method. The advantage of the natural-pressure gas-lift well operation method is a significant reduction in operating costs (electricity, electric submersible pump rent). At that both, new wells drilled into the gas cap and production wells where a breakthrough of gas has occurred can be used as a donor well. A feature that defines this operation method is a need for continuous control over pumping down each borehole. This is due to the fact that a donor well provides several producing oil wells with active gas, the operational parameters of these may significantly differ from each other. A system with automatic lock shield valves was adopted to automate the injection of gas in the Orenburg oil and gas condensate field, it allowed tuning up the injection, constantly monitoring and metering consumption of gas for each well. This paper outlines the Gazpromneft-Orenburg experience in adopting an intelligent system for gas injection monitoring. It is described as a stage of a technical task preparation, conducting pilot runs at several wells, adjusting requirements to the equipment based on the results of pilot runs, full-scale implementation of the project at all wells of the deposit, optimization of gas-lift wells throughout the well stock.
Most wells drilled in 2015–2017 in the Volga-Ural Region of Russia experienced serious downhole problems related to mud losses, which account for a substantial share in total non-productive time (NPT). With conventional methods such as cement plugs, etc. used to solve the lost circulation problem, it takes on average 4 to 6 days per well, or 6 to 10% of the total rig time. In some cases, however, the losses are so heavy that there is no mud return to surface at all, and it may take up to 30 days (about 50% of the rig time) to stop these disastrous losses. Besides, there may be several thief zones at different depths with different loss initiation points. Conventional methods of lost circulation control generally fail.
In many cases, conventional cement plugs used to stop mud losses are inadequate to meet such challenges. This paper describes the application of special cryogenic equipment and chemicals to offer oil and gas well operators an alternative solution based on foaming base cement slurries, spacers, and drill muds with inert gas (usually nitrogen) over a wide range of densities.
When cementing is used for controlling lost circulation, computer-based simulation is essential to determine hydraulic model parameters. A new proprietary cement service performs high-precision foam cement calculations based on actual well data. The key is to select the correct concentration of nitrogen in foam water spacer and foamed cement to reduce hydrostatic pressure below the point at which losses are initiated in a weak horizon (formation). This special foam cementing equipment is capable of controlling nitrogen concentration automatically and injecting nitrogen into base cement with the foamer to maintain the design density of foamed cement. Cement and service water are foamed under high pressure on the surface in a high-pressure pipeline loop system. Automatic foaming means that three main units are simultaneously in operation: a cementing unit, an N2 unit, and an automatic chemical injection skid. Foamed cement is pumped under pressure to drilling tools. Similarly, service water is foamed to produce foam water spacer with a density of 0.3 g/cm3 to 0.9 g/cm3, which is injected into the well before foamed cement. Foam water spacer is injected first in the thief zone followed by foamed cement. The high-viscosity foam water spacer prevents foamed cement from being washed away by formation fluid and reduces the flow of formation water in the thief zone. As a result, the linear velocity of foamed cement in the lost circulation horizon is reduced, which makes it possible for the cement to achieve the required consistency and isolate the weak formation in the near-wellbore area. Foam water spacer injected into the well lowers hydrostatic pressure and raises the static level of fluid in the well to the wellhead to help ensure returns to surface.
The new technology has proved to be the most efficient among other solutions used to mitigate or eliminate mud losses during well drilling in the Volga-Ural region. Foam cementing has reduced the time required to address loss-related problems to two days. This paper discusses the case study of foam cementing used to resolve the lost circulation problem by plugging the thief zone with foamed cement.
Digital technologies have a huge impact on our everyday life, including manufacturing industry, becoming a foundation for operations of large enterprises and corporations. Digital age offers unlimited opportunities while specifying rigorous requirements. Being essential for national economy oil and gas industry is not an exception: easy-to-reach oil is running low, hydrocarbon production is getting more accurate and science-based at all stages. It is necessary to search for different creative ways by using latest technologies to take the lead. Industry leaders create entire structures which provide analytical and scientific support of oil production and oil processing at all levels of manufacturing.