Al-Kandary, Ahmad (Kuwait Oil Company) | Al-Fares, Abdulaziz (Kuwait Oil Company) | Mulyono, Rinaldi (Kuwait Oil Company) | Ammar, Nada Mohammed (Kuwait Oil Company) | Al naeimi, Reem (Baker Hughes) | Hussain, Riyasat (Kuwait Oil Company) | Perumalla, Satya (Baker Hughes)
Role of geomechanics is becoming increasingly important with maturing of conventional reservoirs due to its implications in drilling, completion and production issues. Exploration and development of unconventional reservoirs involve maximizing the reservoir contact and hydraulic fracturing both of which are heavily dependent on geomechanical architecture of the reservoirs and thus require application of geomechanical concepts from the very beginning.
To support the unconventional exploration and conventional reservoir development in Kuwait, country-wide in-situ stress mapping exercise has been carried out in nine fields of Northern Kuwait. Stringent customized quality control measures were put in place to evaluate stress orientation. Cretaceous and sub-Gotnia Salt Jurassic rocks exhibit distinct patterns of stress orientations and magnitudes. While the variations in stress orientation in the Cretaceous rocks are within a small range (N40°E-N50°E) and consistent across major fault systems, the Jurassic formations exhibit high variability (N20°E-N90°E) with anomalous patterns across faults as well as in the vicinity of fracture corridors. Moreover, the overall stress magnitudes were found to be much higher in the strong Jurassic section compared with the relatively less strong Cretaceous strata. During the analysis, it was also observed that several natural fractures in Jurassic reservoirs appear to be critically stressed with evidences of rotation of breakouts.
Using geomechanical models from a specific field, the effects of in-situ stress, pore pressure and rock properties on formations were evaluated in inducing wellbore instability during drilling operations in a tight gas reservoir. It was found that the most favorable orientation for directional drilling is parallel to the maximum horizontal stress (SHmax) within that field.
The geomechanical study provided inputs not only for wellbore stability during drilling, but also regarding the response of natural fractures to in-situ stresses to become hydraulically conductive (permeable) to act as flow conduits. The fracture model of the field shows that the dominant fracture corridor trend in the field is NNE coinciding with present day in-situ maximum principal stress direction.
One of the major challenges of drilling and completion of oil and gas wells is the uncertainty in the formation fracture gradient and the fracture pressure. It is not uncommon that many drilling companies have spent money, resources and time in drilling and completing wells that should have been simply and optimally done. Fracture gradient evaluation constitutes one of the essential parameters in the pre-design stage of drilling operations, reservoir exploitations and stimulations. Several calculation methods and computer models have been presented in the literature for different regions of the world. Most of these techniques were based on either parametric or empirical correlations, which required a prior knowledge of the functional forms or the use of empirical charts which were not very accurate.
This paper presents an innovative method of predicting formation fracture gradient for Gulf of Guinea region. A combination of "Mathew and Kelly?? correlation, "Hubbert and Willis?? correlation and Ben Eaton mathematical models were used in developing the simplified technique based on field data from the Gulf of Guinea. The model compared favorably with the existing fracture gradient results in the Gulf of Guinea with less than 1 % deviation from other correlations thereby saving the rigors and time in using tables, charts and other long techniques. Although the method was developed specifically for the Gulf of Guinea, it should be reliable for other similar areas provided that the variables reflect the conditions in the specific area being considered.
Acharya, Mihir Narayan (Kuwait Oil Company) | Kabir, Mir Md Rezaul (Kuwait Oil Company) | Al-Ajmi, Saad Abdulrahman Hassan (Kuwait Oil Company) | Pradhan, San Prasad (Kuwait Oil Company) | Dashti, Qasem M. (Kuwait Oil Company) | Al-anzi, Ealian H.D. (Kuwait Oil Company) | Chakravorty, Sandeep (Schlumberger)
The deep, sub-salt reservoir complex is tiered with fractured tight carbonate at bottom and top, with the two sub-units of "upper unconventional kerogen?? and "lower inter-bedded kerogen-carbonate?? in the middle. This depositional setting is challenging for horizontal well placement where the thicknesses of respective sub-units are about 50 and 30 feet with varying geomechanical and petrophysical properties. Additionally, this complexity poses limitations in completions and effective stimulation of the Kimmeridgian-Oxfordian reservoirs in several gas fields at development stage in Kuwait.
A horizontal well is placed in the lower sub-unit of the laminated complex of unconventional kerogen and fractured carbonate reservoir as a Maximum Reservoir Contact (MRC) type well. A pilot mother-bore was drilled and logged to identify the lithological properties across the entire vertical domain - facilitates the optimization of horizontal drain-hole placement within the targeted reservoir units.
No wellbore stability issues in drilling were predicted based on the geomechanical understanding where core-calibrated logs from offset vertical wells were considered. However, this modeling method did not have the functionality to integrate the impact of drawdown on the laminated formation which became unstable and collapsed during the short open-hole drill-stem test (DST) plugging the tubing prior to the final completions. An alternative "book-shelf?? geomechanical model was considered at pre-drill stage for predicting the wellbore stability. Once the drilling was completed, the time-lapsed multi-arm caliper indicated the validity of the alternative methodology in predicting the unstable stack of laminations in kerogen-rich strata.
The paper discusses an optimization methodology to enhance the understanding of static and dynamic geomechanical stability through the use of BHI data. Objective of the proposed method is to help improve the effectiveness of completions where wellbore stability due to geomechanical complexity in stacked-pay reservoirs is a primary wellbore challenge in deploying the completions and executing a subsequent stimulation and testing campaign.
Hassi Messaoud in Algeria has been a major oil-producing field for more than 50 years, with many hundreds of wells successfully drilled. The complex geological structure and varying amounts of depletion mean that 3D geomechanical modeling techniques bring great benefit, particularly in predicting well-bore stability, sanding potential, and hydraulic fracturing. This paper describes such a model for one sector of the reservoir, creating 3D maps of mechanical properties and a 3D stress state that can be updated over time as pore pressures change. Several new methods of applying the results to well design are presented, including the creation of "mud weight cubes?? and "sanding potential cubes?? to assist with trajectory optimization and mud weight selection, and to provide limits on safe drawdown.
This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 157031, "Application of Nanotechnology in Drilling Fluids," by Katherine Price Hoelscher, SPE, Guido De Stefano, SPE, Meghan Riley, SPE, and Steve Young, SPE, M-I SWACO, prepared for the 2012 SPE International Oilfield Nanotechnology Conference and Exhibition, Noordwijk, The Netherlands, 12-14 June. The paper has not been peer reviewed.
In this paper, several new developments regarding the failure, fracture and fragmentation of rocks will be discussed. The first topic discussed is the development of true-triaxial failure criteria that involve all three principal stresses. The next topic is a new approach to modelling the propagation of cracks and fractures using accurate local calculations of the stress intensity factor. Lastly, a method for fracture-driven rock fragmentation with a velocity-dependent propagation law is discussed.
This paper presents the results of an integrated laboratory and numerical modelling study on the effect of wellbore deviation and wellbore azimuth on fracture propagation in poorly consolidated sandstone formations. The goal of this project was to develop an understanding of how fractures would transition from single planar fractures to non-planar transverse fractures for fields in the deep-water Gulf of Mexico.
The foundation of this work was over 40 fracturing laboratory tests to measure fracture propagation geometries for a range of well deviations, differential horizontal stresses and rock strength. The samples tested were from three outcrops with unconfined compressive strength (UCS) values ranging from 300 - 1000 psi. For boreholes having low deviation angles and small differential stresses a vertical single planar fracture was created, aligned with the wellbore, as expected. As the well trajectory and stress contrast increased the fractures became more complex, with transverse turning fractures no-longer aligned with the wellbore.
These laboratory results were used to develop and calibrate a new fully-3D finite element model that predicts non-planar fracture growth. The model matches the details of the laboratory tests, including the transition from planar vertical to non-planar transverse fractures as the well deviation, azimuth and stress differentials increase. After initial model development and calibration was complete a model of a complex case was run before showing any experimental results to the modellers. The model successfully predicted the transverse non-planar results found in the laboratory; this gave us increased confidence in the model as a predictive tool.
This work has now been applied with excellent success to four deepwater fields. We have recommended changes in maximum well deviations, performed post-job analyses on wells that had high deviations, and have increased our understanding of the impact of layered formations on fracture growth in these fields.
Lost circulation caused by low fracture gradients is the cause of many drilling related problems. Typically the operational practice when lost circulation occurs is to add loss circulation materials (LCM) to stop mud from flowing into the formations.
To improve the treatment for lost circulation caused by low fracture gradients, especially designed materials in mud system are used to seal the induced fractures around the wellbore. This operation is in the literature referred to as wellbore strengthening that has been found to be a very effective in cutting Non-Productive Time (NPT) when drilling deep offshore wells. Size, type and geometry of sealing materials are debating issues when different techniques are applied. Also the phenomenon is not truly understood when these techniques applied in different sedimentary basins.
This paper presents development and simulation results of a three-dimensional Finite-Element Model (FEM) for investigating wellbore strengthening mechanism. This study also describes a procedure for designing Particle Size Distribution (PSD) in field applications. To better understand the numerical results, the paper also reviews the connection between Leak of Tests (LOTs) and wellbore hoop stress and how these LOTs can mislead in fracture gradient determination.
A comprehensive field database was collected from different sedimentary basins for this study. Results demonstrate that the maximum attainable wellbore pressure achieved by wellbore strengthening is strongly controlled by stress anisotropy. Results also show that Particle Size Distribution (PSD) of wellbore strengthening should be designed in order to seal the fractures close to the mouth and at fracture tip. This will result both in maximizing hoop stress restoration and tip-screening effects. In addition this model is able to show the exact fracture geometry formed around the wellbore that will help to optimize the sealing materials design in wellbore strengthening pills. To support numerical modeling results, near wellbore fracture lab experiments on Sandstone and Dolomite samples were also presented. Laboratory experiments results reveal importance of rock permeability, tensile strength and fluid leak-off in wellbore strengthening applications.
Narrow pore-fracture window in deep and ultra-deep offshore environments, highly deviated wellbores and depleted formations is the most prominent drilling challenge today. Lost circulation and high non-productive time due to the tight window is the major motivation for widening operational window and using wellbore strengthening techniques. Wellbore strengthening can be defined as "a set of techniques used to efficiently plug and seal induced fractures while drilling to deliberately enhance the fracture gradient and widen the operational window??. This technology has the potential to mitigate the lost circulation problem, and improve wellbore integrity to avoid well control disasters. In addition, it might reduce the number of casing strings required to drill deep water wells.
Previous joint industry projects (DEA-13 and GPRI) conducted experiments to investigate lost circulation. The main finding from these projects was the ability to increase fracture reopening pressure by using specific type and size of materials in the drilling fluid system (Morita et al., 1996a, b, and Dudley, 2001). Investigating the physical mechanism that enhances the fracture gradient was not truly feasible using these experiments. Therefore, a clear understanding regarding the effect of material properties (size, type and strength) of the actual sealing mechanism was never achieved but spurred continuous investigations on how drilling fluids can improve the fracture gradient. Table 1 summarizes the wellbore strengthening methodologies, whereby some of them differentiate in the mechanism involved, material type and strength to be used plus the necessity for tip isolation.
Gas drilling has many advantages such as high drilling speed and reservoir protection, however, there are many problems limiting its development. For example, when gas drilling encounters geological risks, drilling fluid must be filled. The process of gas-liquid medium transition will make liquid flow into the fractures in the rock around borehole wall, which may lead to serious borehole wall collapse. In this way, the problems brought by gas drilling counteract its advantages. Thus, this paper puts forward using nanotechnology to reverse the wetting of hole-wall rock before filling drilling fluid into the well bore. The core of this technique is the application of the high-speed gas current jetted by the nozzle of bit to atomize the solution. The low-activity and low-tension solution will carry nano wetting reverse agent and shale anti-swelling agent to ascend with gas along borehole wall. In this way, the dry rock will absorb the solution with agent, and the wetting of fractures can be reversed. After drilling fluid is filled. The capillary effect can prevent further penetration of drilling fluid, and the film on the fracture can avoid the swelling of argillaceous earth. Thus, the fracture won't expansion on the surrounding rock of the borehole. Compaired with existing techniques, the strength of the borehole wall can be improved by 50% by taking advantage of this technique. Instead of the previous research method from perspective of drilling fluid, the technique can directly change the nature of fracture surface with small amount of treating agent to avoid the expansion of fractures. Besides, the technique can effectively reduce the friction between drilling pipe and borehole wall. The technique is expected to avoid the problems of high cost, pollution, ineffectiveness, and achieve the goal of keeping the wellbore stability in gas liquid medium transition in gas drilling process.