Meng, X. (SINOPEC Petroleum Exploration and Production Research Institute) | Zhou, H. (SINOPEC Research Institute of Petroleum Engineering) | Fan, H. (China University of Petroleum) | Peng, Q. (China University of Petroleum) | Deng, S. (China University of Petroleum)
With the oil and gas exploration and development in deep formation and the number of deep wells grow continually, the ROP decreases greatly and the cost of drilling operation increases rapidly. A comprehensive procedure of optimization hydraulic design for improving ROP was formulated. It can conduct the integrated hydraulics design to improve ROP not only during making the drilling design, but also can generate recommendations of hydraulic optimization for improving ROP in the process of drilling based on the real-time drilling situation.
First, this paper presents a mathematical analysis of the hydraulics (Bit pressure drop, bit specific hydraulic horsepower, et al.) influence on the ROP based on the drilling engineering data of several wells of Tarim basin in west China,. In order to eliminate the influence caused by the difference of the other drilling data, all of them were normalized in this process. Second, according to the problem that no single rheology model can describe exactly the rheological properties of all types drilling fluids, a systemic hydraulic optimization approach was established, which is applicable for all common rheological models. For improving the design precision, the flow channel both in pipe and annuli was divided into several sections and the flow regime change of each section was considered. Moreover, for maximizing the ROP, the size of drill pipe size was considered during the process of hydraulics optimization.
The technology has been applied in several wells in Tarim basin of China and the test formations are about 3535m-6935m depth. Based on the novel and systematic method, the optimal drill assembly, flow rate, pump pressure, nozzle combination and others drilling parameters were all obtained. The results show that the ROP of these wells were improved about 10.5%~80%.
Through the application of the proposed method, the results show that the ROP in deep and ultra-deep well has been improved obviously, and which have decreased the cost of drilling operation greatly. Therefore, this method can afford an effective approach to improve ROP in deep well.
Kiatrabile, T. (PTT Exploration & Production) | Noosri, R. (PTT Exploration & Production) | Hamdan, M. K. (PTT Exploration & Production) | Kusolsong, S. (PTT Exploration & Production) | Palviriyachote, S. (PTT Exploration & Production) | Suwatjanapornphong, S. (PTT Exploration & Production) | Rattanarujikorn, Y. (PTT Exploration & Production) | Sarisittitham, S. (PTT Exploration & Production) | Piyajunya, T. (PTT Exploration & Production) | Phonphetrassameekul, N. (PTT Exploration & Production) | Manai, T. (Schlumberger) | Adisornsupawat, K. (Schlumberger) | Mustapha, H. (Schlumberger) | Press, D. (Schlumberger)
The main objective of this paper is to present the assessment and methodology that would improve the tight oil recovery by hydraulic fracturing (HF) wells. The methodology is enabled by a fully integrated workflow orchestrating petro-physical log interpretation, static modelling, and dynamic modelling coupled with rock mechanics for an optimal fracturing design and mitigating the underlying risks.
In the past, well placement in tight reservoirs and HF design were performed mostly based on available analogous data of offset wells using rock mechanics parameters such as stress magnitude and regional stress orientation to predict the fractures that would propagate through the reservoir in a certain location and well orientation, the stress/strain regime is one of the key parameters that plays an important role. It is also the key performance indicator for developing the tight oil reservoir with underlying complexities.
The process is initiated by the conventional static modelling which involves structural framework construction, distributing the petro-physical characteristics subject to the well logs and other available subsurface data. The second step is to perform a history match of a derived dynamic model by honouring the observed data. This process helps in calibrating the model to be able to represent reservoir dynamic behavior. The results of the history matched model; i.e., reservoir pressure through time is the key input for the Mechanical Earth Model (MEM) in the next step. The MEM process starts with the construction of a 1D MEM using well log advanced scanner and rock mechanics properties from laboratory to represent the strength and elastic properties of the rock where existing wells have been penetrated into the reservoir layers. Hence, a coupled dynamic reservoir simulation with 3D geomechanical model will yield a realistic relationship between the current reservoir depletion state in terms of pressure and the current stress strain regime. This relationship is paramount for optimal location indentification of the fracturing wells and corresponding design together with an estimation of the subsequent recovery. Also, the rock mechanic simulation study would yield a comprehensive result with respect to the reservoir mechanical integrity while conducting the hydraulic fracturing operation to increase the well productivity.
This integrated workflow is considered as the key step for tight oil reservoir development, and it can be expanded to unconventional resources for a better reservoir characterisation and reservoir development. The study was performed within close collaboration within the teams with comprehensive know-how sharing and exchange.
Zou, S. (The University of New South Wales) | Hussain, F. (The University of New South Wales) | Arns, J. (The University of New South Wales) | Guo, Z. (The University of New South Wales) | Arns, C. H. (The University of New South Wales)
Image-based computations of relative permeability require a description of fluid distributions in the pore space. Usually the fluid distributions are computed on the imaged pore space. Recent advances in imaging technologies have made it possible to directly resolve actual fluid distributions at the pore scale, thus capturing a large field of view for arbitrary wetting conditions, which are numerically difficult to reproduce. In previous studies fluid distributions were not imaged under in-situ condition, which may cause oil (non-wetting) phase to snap-off. Consequently computed oil relative permeability is underestimated particularly at low oil saturations. This study extends our previous work by imaging fluid distributions under in-situ conditions as basis for the numerical computations.
In this study, we perform steady state flow test on a homogeneous outcrop sandstone (Bentheimer) core. First, the dry core is imaged in our micro-CT facility. Afterwards the core is fully saturated with 0.4 molar NaI solution. The saturated core is then mounted in a specially designed flow cell which allows the flow experiment to be carried with the core mounted on the CT scanner. Afterwards steady state injection of oil and brine is carried out at four different oil/water injection ratios. For each injection ratio, steady state pressure drop is noted and in-situ fluid distributions are imaged under flow conditions. These imaged fluid distributions are used to compute image-based relative permeability. While the measured pressure drops are used to calculate experimental relative permeability.
In conclusion, the match between the relative permeability computed from imaged fluid distributions and experimental measurements is excellent. Results demonstrate that imaging in-situ fluid distributions allows us to overcome significant limitations of our previous work: 1) measured and computed oil relative permeability are in close agreement for whole saturation range and 2) laboratory capillary end effects at the core outlet can be imaged which allows us to apply a correction to the laboratory measured data.
In the present study, we examine the possibility to estimate the anisotropic properties of formations from the waveforms obtained by acoustic logging using numerical simulation. Our numerical model includes a vertical borehole in anisotropic layer with various azimuths. The anisotropic layer is set as transversely isotropic medium with a horizontal axis of symmetry (HTI) or transversely isotropic medium with a tilted axis of symmetry (TTI) which has 5 independent elastic parameters in the stiffness matrix. It has been assumed in the acoustic logging that the medium to estimate the anisotropy is HTI or TTI with a subtle tilt angle under the assumption of weak anisotropy and the shear wave splitting is used to estimate the azimuthal angle and the order of anisotropy with cross dipole acoustic measurements. Since it is necessary to have a general method that could deal with TTI in terms of both the tilted angle and the order of anisotropy, we conduct numerical experiments under a hypothesis that the cross dipole waveforms could be exploited for further data processing. We then apply a method of Full Waveform Inversion (FWI) for acoustic logging model in isotropic medium to investigate the effectiveness of the method. Our results show that the waveforms include information about the anisotropic layer even if no difference can be observed in the travel time. Besides, it is suggested that FWI technique for anisotropic medium should be useful to estimate the anisotropic parameters in the acoustic logging.
Serdyuk, A. N. (Rosneft) | Frolenkov, A. N. (Rosneft) | Valeev, S. V. (Rosneft) | Sitdikov, S. S. (Rosneft) | Shchekaleva, T. (Schlumberger) | Roukhlov, V. (Schlumberger) | Yudin, A. V. (Schlumberger) | Gromovenko, A. V. (Schlumberger)
The effective alternative method of multi stage fracturing stimulation of horizontal section of sidetracks completed with cemented liner and utilization of abrasive perforating technique started to be implemented in West Siberia for Priobskoe and Prirazlomnoe oil fields. The goal was to analyze all associated risks, make clear statistics and adjust it for specific oil fields for further implementation on a massive scale.
Abrasive perforating is done through coiled tubing (CT) special downhole perforator that creates holes inside casing and caverns in nearwellbore zone by pumping sand slurry down CT string. After perforation has been done and the well has been stimulated with fracturing treatment, fiber-enhanced proppant plug is placed in order to isolate treated intervals. Adding degradable fibers to proppant plugs helps to achieve successful and efficient isolation between stages, while conventional proppant plugs are non-applicable due to gravity effects that cause settling of proppant and resulting in non-uniform proppant distribution and poor isolation efficiency.
Extensive campaign was conducted in 2015 at Priobskoe and Prirazlomnoe oil fields, located in Khanti-Mansijsk region. The main challenge during all operations was to perform a successful bridging of wide hydraulic fractures. Different approaches to get isolation were used and the most effective variant is narrowly described. Also spacing and number of perforating stations were identified as critical parameter. First operational and wells productivity results look very promising and the technique was proven as a best option of multistage stimulation in short and slim sidetrack wellbores. Such sidetracks have been shown as efficient method to improve hydrocarbons recovery from mature fields.
A comprehensive review of trial campaign with utilization of special technique is presented. Slim sidetracks can be stimulated with several stages in reliable, efficient and economical manner. Technology can be utilized for other brown fields in the region and outside Russia.
Smart Water and Low Salinity EOR is established as a techno-economically promising method through laboratory coreflood studies and single well tracer studies in field pilot cases. The method is based on lowering salinity of injected water and spiking of multivalent ions such as Mg2+, SO42−, PO43− ions. Wettability alteration and expansion of electrical double layer are attributed to the trapped oil release mechanism. This however invites the possibilities of induced and aggravated scale deposition if the formation water is rich in divalent cations (as in the case of carbonate formation). The resulting formation damage and reduced well productivity may negate the advantages of smart waterflood. This article presents the outcome of an extensive study, conducted to optimize smart water composition targeting an offshore carbonate reservoir. After quantifying the scaling potential at reservoir condition, a Polyphosphate compound is introduced which arrested the scale precipitation. Through contact angle, interfacial tension, Zeta-potential and drainage studies it is established that new formulation not only has reduced scaling potential but also enhanced ability for oil recovery.
The wide implementation of hydraulic fracturing in shale reservoirs and the interactions among hydraulic fractures, natural fractures and the shale matrix have brought great challenge for reservoir studies using conventional finite-difference-based reservoir simulators. This work establishes a dynamic approach for the simulation of fractured shale reservoirs that incorporate the embedded discrete fracture model (EDFM) as well as the multiple porosity model, which is necessary for simulating the complex transportation process in shale reservoirs.
In this paper, we extend the EDFM approach for fractured shale reservoirs to a multi-continuum context, in which one fracture segment can have mass transfer with multiple parent grid blocks in favor of the complex porosity types of shale formations. The reservoir model can be updated dynamically during the simulation with our in-house simulator to consider the change of the fracture network due to fracking and refracking at different stages of field development. This is achieved by altering the effective non-neighbor connections with time that are associated with the fracture system. Therefore the reservoir with a changing fracture distribution can be modeled with a single simulation. The formulation is based on finite volume rather than finite difference to facilitate the unstructured nature of the reservoir model.
The result is compared with the explicit fracture model with PEBI grid blocks to evaluate its accuracy. For the test case of a horizontal well with multiple hydraulic fractures and large scale natural fractures, the simulation result can be matched with great accuracy. Sensitivity analysis to grid refinement is also conducted, which proves the model only need moderate grid refinement to obtain desirable accuracy.
This work established a more flexible and efficient yet more accurate approach for fractured shale reservoir modeling, with the emphasis on improving the ability to model the fluid transportation among different porosity types. The proposed model improves the simulation by reducing the complexity of the gridding process, cutting the total number of grid blocks, and significantly decreasing the CPU time. It provides a coherent method for characterizing the fluid transportation in fractured shale reservoirs, which is usually a difficult task with traditional reservoir models.
The main objective of this study is to construct a geological and static reservoir model of the interpreted karst reservoir in Nang Nuan Oil Field (NNN) in order to obtain hydrocarbon accumulation zone of the field. The target intervals are Permian Ratburi carbonate and Tertiary polymitic conglomerate which are suspected to be potential reservoir. This study started with the review of previous literatures and all available subsurface information such as conventional core, electric logs, production data, 3D seismic etc. Hence, the geological model was reconstructed and proposed to use for static reservoir model. Electrofacies was identified during the data preparation phase in order to get the link of lihofacies and electric log including petrophysical properties. The numerical model was constructed following the basic static reservoir modelling workflow. Regarding integration of all information in hand, the geological model of this study is partly different from the previous model. The most significant difference is the reservoir facies. This study proposes Tertiary conglomerate facies from interpreted alluvial fan deposits as the reservoir instead of Permian carbonates meanwhile the dissolution is still the main key of porosity development. In term of numerical model, the sequencial indicator simulation is used for distribute facies and petrophysical properties in spatial. According to the result of this study, the reservoir geometry and porosity development were changed from the existing model. The geometry of carbonate karst tower is restricted in term of the area meanwhile Tertiary conglomerate from alluvial fan deposits is more extensive and the key that advocates the increasing of dissolution is stratigraphic break. The result of this study changes reservoir facies which impacts possitively to distribution of petrophysical properties. Thus, the new model may lead to re-think of the field value and make it becomes viable again.
Integrated geophysical applications and well datasets play an important role in understanding reservoir distribution and decision making for a robust development plan. A technical assessment was completed in a gas field in the North Malay Basin to describe the reservoir heterogeneity in the Early Miocene to Late Oligocene reservoir intervals. The field is a North-South oriented plunging anticline with stratigraphic trap configuration, discovered in 2007 by Well-X1. The assessment has resulted in a proposal of an appraisal well in 2014, Well-X2ST to delineate the northern hydrocarbon extent and to assess the hydrocarbon potential in the exploration interval of deeper sequences. The new well datasets were acquired and the results were utilized to further evaluate the field.
This paper focuses on the deepest reservoir sequence, DS12, encountered by the appraisal well in the eastern flank of the Malaysia-Thailand Joint Development Area (MTJDA). Rock physics modeling and seismic attribute datasets with well log and pressure data integration were utilized to better understand sand distribution for the upcoming development planning. Due to the thinly bedded nature of the reservoirs, the seismic could not be fully utilized to evaluate internal stacking geometries. This was further complicated by attenuation from the overlying thick shale. However, attribute analysis was effective to determine overall sand presence where the bed thickness ranges from 10 to 15 meters and the seismic detection limit is approximately 8 meters.
Rock property analysis was performed to calibrate both acoustic impedance and Vp/Vs to gamma ray for indication of sand presence. The Vp/Vs derivative was used instead of acoustic impedance because of the extra information obtained in both the elastic and AVO domain. In addition, rock physics modeling was performed to differentiate gas from wet sand and shale. The seismic datasets were used to qualitatively condition a geologic model to better distribute sand presence for well planning optimization. Development wells are planned to target good quality sands to maximize recovery efficiency
The success of proving the deepest reservoir sequence in the eastern flank of MTJDA, utilizing geophysical application and well data integration, have resulted in an improved understanding to outline deep reservoir distribution in the surrounding area and mitigate uncertainties in the development plan.
Before undertaking any seismic interpretation project, it is essential to understand the rock physics of the area so that the interpreter knows what to look for in their seismic. Rock physics modelling can be used to predict the effects of lithology, fluid, porosity, depth and sand thickness on the seismic response. It can also help to understand whether direct hydrocarbon indicators (DHIs) such as flat spots, bright spots, dim spots or polarity reversals are expected and also the best seismic attributes to use to identify hydrocarbons. Well ties can be used to determine the quality of the seismic data and infer how reliably predictions based on the rock physics can be applied back to the seismic data.
The rock physics of several producing assets across the Gulf of Thailand have been examined and compared. Rock properties of over 200 wells have been analyzed based on stratigraphy, lithology, fluid fill, facies, porosity and depth. It was observed that the rock physics could be split into two distinct regimes based upon depositional environment separated by a key unconformity.
The first rock physics regime is observed in the shallow high porosity fluvial systems found within the Nong Yao Field and the younger reservoirs of the Jasmine and Manora Fields. In this regime, seismic attributes and seismic inversion have been successfully used to predict sand presence and thickness. Sands and shales have distinctly different rock properties and sands produce a strong class III-IV Amplitude Varation with Offset (AVO) response. Fluid effects can be observed on seismic although it is difficult as thickness and porosity changes may be incorrectly interpreted as fluid changes. The second rock physics regime is observed in the older, lower porosity lacustrine system found within the main reservoirs of the Manora Field and the pre-MMU reservoirs of the Jasmine Field. Within this regime, lithology prediction is much more difficult as sands and shales have very similar properties. Sands are modelled to have a class I-II AVO response and fluid effects are minimal.
Understanding the rock physics of these fields allows future work to be focused appropriately. At the Nong Yao Field and in the younger section of the Jasmine Field, technical work is focused on seismic inversion, seismic attribute analysis and other geophysical techniques for lithology and fluid prediction. Whereas at the Manora Field and in the older reservoirs of the Jasmine Field, technical work is focused more on structural mapping and geological modelling, and amplitude analysis is of lower priority.