Low-permeability, low-production, low-abundance are the major features of the low-permeable gas reservoir. Commingling production has been widely used as an important method to improve the producing ability of gas reservoirs, however, the dynamic analysis and technical countermeasures for the multi-commingled wells are still not enough.
Started from the multi-commingled filtration theory model, the pressure characteristics and the contribution rate of production of each layer, which are under the different multi-commingled well conditions such as reservoir properties differences, interlayer pressure difference and different damage degree, are studied in this paper. The results show that the contribution rate is fixed on formation coefficient before the pressure wave reaches the boundary; and after that, it is fixed on the storage ratio, it could be fixed on the formation coefficient, storage ratio and kickoff pressure gradient when considering the kickoff pressure gradient. Although there are significant differences in permeability between layers, the well test pressure curves have little difference.
Taking the Da-niudi gas field for example, the single layer production rate, recovery and total recovery are studied by numerical simulation at different permeability ratio in multi-commingled well. The results show that the different permeability ratio contrast (<10) models can all be commingled. The total recovery of different models has little difference, when the formation pressure declines to the abandonment pressure. However, the smaller the permeability contrast is, the longer the stable production period of the well is, and the less the interlayer recovery difference is; on the contrary, the shorter the stable production period is, and the larger the interlayer recovery difference is.
All the reservoirs in the multi-commingled well had better to be put into operation at one time. In this way not only the operation to succeed the late fill-holes can be saved, but also overall commingled layer recovery could increase.
With the development of the ecnomic, the demand for energe is increasing graudally and the development of the gas resource increases multiply; however, the gas reservoirs with low-permeability, low-porosity and thin thickness, distribute widely in our country and has large reserves. The reservoir can't be developed effectively since the deliverability of the single layer in the reservoir with low-permeability, low-porosity and thin thickness is usually very low. Liao Pingfang and Guan Zhiqiang et al[ref. 1] have taken the theory study about the commingled production for Se-bei No. 1 gas field in Tarim Basin. They calculated the interlayer interference of the commingled well by numerical simulation, presented a reasonalbe optimum perforation width and effective thickness and the theory was also proved in practice. Based on the study, Xiong Yu and Zhang Liehui et al[ref.2] studied on technical threshold value of multiple-zone production with one well for multi-layered gas reservoir. Xiong Yanli et at[ref.3] studied the dynamic behavior and development fruitage analysis for the commingled production well. Zhong Bing et al[ref.4] studied the methods of proper allocation for the commingled production well in multi-layer sand reservoir. The other investigation[ref.5-10] also shows that the commingled production has been an important method used to improve the producing degree of the low-permeable gas reservoir. This paper starts from the filtration theory model, then uses the numerical simulation, taking the Da-niudi gas field for example, to study the mechanism of commingled production in low-pemeable gas reservoir.
With the development of deepwater oil and gas fields in china, the demand of high strength marine drilling riser augments gradually. All the riser depends on importing, so the technology of high strength riser must develop in order to sinicization. After investigation on national and foreign standards about marine riser, it was found that there was not material properties standard of marine drilling riser. This paper mainly studied and established material properties standard of marine drilling rise, combined with material test of X80 steel above 20in, and analysed existing standards. Finally the material performance index of X80 steel marine riser had been established, which pushed the localization process of high strength riser.
Key words deep water;marine drilling riser;material;standard;
Formation micro imager is applied in geological investigation of borehole which can provid much more properties than core sample collection. In this paper, the photogrammetic method is discussed during the lab test based on images. Photogrammetric technology is the technique of measuring objects (2D or 3D) from images. During the test process, 35 printed target points are set on the plastic clay which is adhere to the simulation borehole surface and taking photos from different locations to get the points' information. The software of PhotoModeler is used to analyse these photos with fixing the origin point, the direction of 3D coordinate and the distance between any 2 target points. All these points (x, y, z) are obtained in this test by focus length of 18mm, 35mm and 55mm. There are differences between the 3 focus lengths for the same point's x, y and z. The results show that the parameters of RMS (Root Mean Square) marking residual and tightness have negative effection on the precision. We can identify the physical properties of a borehole surface (borehole breakout, fracture, et al.) accurately by this technology to improve exploration and production results utilizing advanced borehole. It also can reduce coring and associated drilling costs (partial core replacement).
According to previous geological achievements,the development of the reef or oolitic reservoir is closely related to sedimentary facies. The reef or oolitic reservoir belongs to hidden lithologic trap, and the sedimentary evolution process and palaeogeomorphology settings of open sea platform-ocean trough sedimentary facies belt formed in the Late Permian in Sichuan basin are very complicated. As the platform continuously increased, ocean trough gradually disappeared in Feixianguan Period.
Furthermore the physical properties of the reef or oolitic reservoirs have features of lithologic traps, such as strong heterogeneity and complex gas-water relationships which make it very difficult for seismic prediction. In recent years, we developed sedimentary facies prediction technique as well as seismic prediction technique series of carbonate reef or oolitic reservoir by tracking on seismic prediction techniques of carbonate reef or oolitic reservoir based on seismic facies.
First, we made fine horizon correlation and sequence stratigraphy analysis, then simulated the multicycle sedimentary evolution process from the Feixianguan to Changxing period. After that, we applied the following techniques: forward modeling, layer flattening, ancient landscape restoration and seismic facies pattern. Finally we established different sedimentary facies belts and made seismic prediction. According to the analysis on the reservoir features of logging data, we established reservoir identification pattern which expressed low gamma and low acoustic impedance. Then we adopted facies-controlled inversion technology, carried out reservoir prediction in the favorable facies belts of reef and oolitic reservoir; finally made gas and water detection with such techniques as waveform
decomposition and frequency alias attenuation and so on.
The empirical range of deliverability ratio between horizontal well and vertical well is usually regarded as 2-5. But actually, this range is too large and the real ratio may not be within it. To quantify the deliverability ratio relationship between horizontal well and vertical well more accurate, the deliverability ratio relationship is derived based on modified Joshi's horizontal well deliverability formula and vertical well deliverability formula. Then as for different horizontal well lengths with known parameters of the pay zone in the vertical well where the horizontal well locates, corresponding deliverability ratios can be obtained. And then the horizontal well deliverability can be predicted by multiplying the known appraisal well (vertical well) deliverability and the deliverability ratio.
Sensitivity analysis between the deliverability ratio and relevant parameters is done by using pay zone, fluid and well parameters of Q oilfield of China Bohai Bay. The results show that as for different parameter combinations, the deliverability ratio can be within or without the range of 2-5; skin factor and off-center distance have little effect on the deliverability ratio, while as horizontal length increases, permeability anisotropy factor increases and pay thickness increases as well as drainage radius decreases, the deliverability ratio will decrease obviously. These regularities coincide with actual development regularity, which verifies the accuracy of the proposed method.
The proposed method quantifies the deliverability ratio range between horizontal well and vertical well, and increases prediction accuracy of horizontal well deliverability; therefore it is of great practicability, especially for early stage reservoir development.
Polymer flooding provides a better mobility ratio than water flooding, for a better sweep especially in viscous oil reservoirs that have been under water flood. During polymer injection, larger fractures may be induced compared with water injection. The geometry and propagation behaviours of fractures caused by the injection of viscous fluids in sands under bi-axial stress that simulated unconsolidated formation were studied. The results showed that the geometry of fractures induced by viscous fluids in an unconsolidated formation is a dominantly planar fracture, although it is very tortuous. In view of isotropic stress in the horizontal plane, multiple fractures were induced in several directions. Similar fractures were observed when the injection fluid viscosity was varied by a factor of 3, while keeping the mobility ratio constant. The tests confirm that the injection pressure should exceed the minimum stress by a factor of 2.5 to induce fracture propagation. Below this pressure only matrix flow occurred, although the permeability was enhanced by the injection.
Key words: Polymer injection; Oil saturation; Unconsolidated sand; Heavy oil; Hydraulic fracturing
Recovery of heavy oil from unconsolidated reservoirs can be improved if the normal water injection is replaced by polymer injection, which provides a much better mobility ratio. Fracture behaviour in unconsolidated rock may be quite different from behaviour in elastic rock. Unlike competent formations, unconsolidated sands beds have little or no tensile stress. Besides, when fracture initiation and propagation, shear failure of this formation plays a key role which was high concerned by previous researchers. At the same time, polymer, as a kind of viscous fluid, could lead to different behaviour of fracture and pressure when compared with water injection. Therefore it is a challenging to predict injectivity and monitor fracture evolution by pressure measurements when using polymer flooding strategy in unconsolidated reservoirs.
Some experimental and simulation work has been done to reveal mechanism of fracture initiation and propagation in unconsolidated sands formation. Khodaverdian found that fracture tip propagation in unconsolidated sand is dominated by fluid invasion and shear failure within a process zone ahead of the tip. A kind of cross-linked guar was used in his injection tests, which induced three different invasion/damage zones: the external filtercake zone, the gel-invaded zone and the filtrateinvaded zone. Later, he demonstrated that fractures propagate at relatively small net pressures in the order of 1-2 MPa through a set of polymer injection experiments in sand blocks for which the boundary stresses were scaled. Pater found fluid rheology has a strong influence on the tendency to fracturing in unconsolidated sand. In their tests, most of the fracture consisted of a dominant main branch with several branches, which highly enhanced the leak-off from the fracture. Besides, the fracture initiation pressure was about 2.5-3.5 times the confining pressure. The simulation of hydraulic fracturing in unconsolidated sands was done by Zhai and Sharma . They found that shear failure is the dominant mechanism when fluids are injected into unconsolidated sands, while tensile failure happens only at the near wellbore region under strike-slip stress conditions.
Catastrophic losses accompanied by reservoir fluid influx that are commonly experienced when drilling oil and gas wells through fractured and vugular carbonates in Indonesia were solved using a managed pressure drilling (MPD) variant called pressurized mud cap drilling (PMCD) to drill through the loss zones and reach target depth (TD) with minimal non-productive time. The well is closed in on a rotating control device (RCD) and a light annular fluid column or mud cap is maintained in the annulus, while sacrificial drilling fluid, mostly water, is pumped through the drillpipe and together with the cuttings, are swept into the loss zones. The method has been largely successful in allowing adopters to reach TD, but difficulties as to how the liner and well completion can be run in PMCD mode have been encountered. The requirements of completing the well in PMCD mode most of the time leads to countless failed attempts to kill the well or circulate a mud weight that is at balance with formation pressure.
Recent PMCD operations, however, have provided success stories as to liner and well completion running, both in the onshore and offshore setting in Indonesia. These successes have largely been brought about by appropriate liner / completion system design and by the adoption of new techniques that complement the procedures involved in operating in PMCD mode. These methods have allowed for the proper management of pressures while running liner / completion with total losses and have subsequently allowed the containment of the same. The details of these methods employed for running liners and well completion safely, efficiently and successfully in PMCD mode in onshore and offshore locations in Indonesia are provided in this paper, as well its capabilities and limitations. The set-up of the liner and completion equipment that have been run in PMCD mode along with recommendations for improvement are also discussed.
Non-Newtonian flows in highly eccentric annuli with cuttings beds, washouts and fractures, encountered in cementing and managed pressure (and underbalanced) drilling, are solved without crude slot flow and hydraulic radius approximations. The nonlinear partial differential equations, written to customized, boundary-conforming, curvilinear coordinate grid systems providing high physical resolution in tight spaces, are solved exactly with no-slip conditions, and detailed velocity, apparent viscosity, shear rate and viscous stress fields are computed for pressure drop, hole cleaning and other applications. For fluids with yield stress, well known uncertainties related to plug zone size and shape are fully resolved using generalized Bingham plastic and Herschel-Bulkley relations applicable across transition boundaries (determined iteratively as part of the solution) reaching into and across the plug. Two-dimensional, single-phase, steady flow simulations, solved rapidly using finite difference methods, provide detailed numbers and color displays for all physical quantities within seconds, with excellent numerical stability for all fluid types with and without yield stress. Formulations for steady-state casing or drillpipe longitudinal translation and rotation are described, and extensions to model transient incompressible effects associated with starting, stopping and periodic movement, important in evaluating cement-mud displacement efficiency, axial-helical cuttings transport, swab-surge, and jarring remedies for freeing stuck pipe, are discussed. Practical problems are presented and the advantages over existing models are described. These methods extend those in the author's books Borehole Flow Modeling in Horizontal, Deviated and Vertical Wells (Gulf Publishing, 1991) and Computational Rheology for Pipeline and Annular Flow (Elsevier, 2001).
Ashena, Rahman (Petroleum U. of Tech Iran) | Moghadasi, Jamshid (Petroleum U. of Tech Iran) | Ghalambor, Ali (U. of Louisiana at Lafayette) | Bataee, Mahmood (Petroleum U. of Tech Iran) | Ashena, Rahim (Petroleum U. of Tech Iran) | Feghhi, Amir
Two phase flow applications in petroleum industry are so widespread. It is a fact that UBD precise bottomhole pressure maintenance ascertains UBD success. UBD hydraulics design, especially for inclined trajectories, is a real challenge. This is greatly dependent on the pressure drop in the annulus.
Two phase flow through annulus is an ambiguous area of study to evaluate the bottomhole pressure. Two phase flow correlations on which most of UBD simulators based on over predict and also make extrapolation risky. Although Mechanistic approaches increase the frequency for designing two phase flow systems in pipes, modeling them through annulus by using the hydraulic diameter concept is not so successful. For this reason, their corresponding errors are not small. Therefore, in this paper, Artificial Neural Network is made use of to evaluate BHP in the inclined annulus using two major Iranian Oil Fields. To compare BHP found by neural network, Naseri et al mechanistic model which is a popular mechanistic model for these two fields is applied.
ANN shows to perform much better than Naseri et al mechanistic model. The results show that neural network can estimate bottomhole pressure with an error of less than 20%. This proves that in case of existence of measured BHP while under balanced drilling, it is worth to use ANN to simulate BHP rather than mechanistic modeling or correlations.
ANN is highly shown to be useful for solving the non-straightforward problem of two phase flow in annulus. Few jobs have been done to prove the superiority of ANN to mechanistic modeling and correlations in terms of pressure prediction especially in under balanced drilling.
Field-wide flow patterns for the 25-year waterflood production history of the medium-high permeability Gudong field, China have been carefully studied using a flow-based numerical simulation process. Through a history matching, field-wide streamline patterns and the cu1mulative flow between injector/producer well pairs can be displayed graphically and quantitatively via well allocation factors. By analyzing the flow pattern or streamline fields (field-wide and locally) for each time step through the reservoir production history, Predominant Streamline Fields (PSF) and Weak Streamline Fields (WSF) can be identified. The PSF can be classified into different levels based on statistically analyzing Strength Index of Streamline Field (SISF), which is a function of both allocation factor and the swept volume of the specific well pair at a given time step. Generally speaking, areas with strong PSF most likely indicate where reservoir channeling occurred at this specific time period, and this channeling is likely to persist until enough change is done. The relative stable WSF zones, with reasonable formation thickness have good potential to be bypassed pay.
To verify the findings above, a dozen conceptual models have been built and tested, and consistent results were found. This dynamic reservoir study processes provided an extra tool for reservoir scale waterflood optimization, well selection for profile modification/water shutoff, and infill drilling.
The Gudong case study indicated that PSF behavior began about 4~ 6 years from the start of water injection. That time period was consistent with a lot of other history data. The findings helped EOR and infill drilling in Gudong field.
Conclusions from this study have led to a better understanding of the displacement mechanisms and the nature-and-man-made dynamic-heterogeneity in the field, which may not be able to obtain otherwise.