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.
Pumping a tail stage of resin coat proppant (RCP) is well documented method to control proppant flowback in a wide variety of oil and gas wells. The performance of RCP can be impacted by reservoir temperature and closure stress, as well as fluid and fracture placement parameters. RCP systems were originally designed for higher temperature applications although the use of lower temperature curable resins in shallow lower stress reservoirs has been discussed since at least mid-2005. 1,2,3 Strong oil prices and relatively weak gas prices have recently (2012) been driving the development of relatively shallow tight oil reservoirs within the Western Canadian Sedimentary Basin (WCSB) including the Slave Point, Cardium, Bakken, Viking and others. These reservoirs typically have relatively low reservoir temperatures and closure stresses which highlight the importance of looking beyond the reservoir temperature with a holistic evaluation of the fracture fluid interactions and fracture placement efficiency that can significantly impact RCP placement and performance; existing SPE publications also provide good background to the impact of these contributing factors.4,5
Most RCP literature focuses on clastic applications. In conjunction with our proppant supplier and pumping service partner, Lone Pine Resources Canada Ltd (LPR) has recently conducted laboratory testing designed to optimize the use of RCP within the Slave Point carbonate reservoir that LPR is successfully developing with multi-fractured horizontal wells (MFHZ). The Slave Point reservoir presents a challenge to RCP performance with a combination of a cool reservoir temperature of 40°C (100°F) and low closure pressures of roughly 20 MPa (2,900 psi).
During Q1/Q2 2012 LPR identified a proppant flowback that was inhibiting production and increasing workover expenditures. Study of the problem identified proppant mixing and a lack of RCP bonding as root cause issues. A holistic review of the LPR Slave Point fracture program resulted in significant changes to the fracture treatment design and execution including the RCP type, resin activation parameters and base fluid changes.
LPR has been able to minimize proppant flowback to the point that bottomhole pump failures as a result of proppant production have been significantly reduced, if not eliminated, and no incremental proppant clean-out operations have been required since the implementation of an optimized fracturing program that includes higher viscosity fracturing fluid and an optimized RCP-LT and activator program. In addition, no measurable proppant flowback volumes have been recovered during initial CT clean-out from the last four July 2012 fractured wells.
These are very positive indicators that the RCP-LT and activator changes, improved fracture fluid viscosity and proppant placement has solved the proppant inflow problem.
Cementing a string in one stage is a challenging task, especially in the presence of weak formations. Cement slurry losses during placement is highly possible if the equivalent circulating density (ECD) exceeds 82 pcf during placement. A conventional method to overcome this challenge is to use multi-stage cementing by setting the stage tool above the loss circulation zone. However, field data indicate that the tool can fail, thus causing serious delay and economic loss. In addition, stage tools are considered weak point and not good for long term seal. A second method for zonal isolation is to use low density cement.
In this study, we present extensive lab evaluation of a low density system based on the use of hollow microspheres for one year at field conditions. The tests included one year mechanical properties measurement such as compressive strength development, Young's modulus and Poisson's ratio. The low-density system (70 pcf) was tested at 300 ºF. An earlier study has shown the suitability of using low density cement in the field, Al-Yami et al. (2007). However, there is no available
Investigation in the literature about the durability of low density cement at higher temperature and at different operational scenarios.
The finite element method was used to analyze the failure probability of HPHT wells over with time. At the variation of bottom whole pressure, the casing, cement, and formation system failure probability was studied for this type of cement.
This paper introduces the operational envelope for this type of cement in order to achieve successful operations. Field cases were discussed to validate the results of this investigation.
Cementing is one of important and crucial issues in oil field especially for high pressure and gas bearing formations. It is difficult to achieve a good zonal isolation in such formation types where pressure is abnormal and formation fluid contains corrosive fluids and gases. A common problem associated with highly over pressurized zones is cross flow after cementing. Fluid flow from an over pressured zone to a low pressure, high permeability zone can lead to deteriorating the existing production hardware. Work over operations that attempt to repair cement voids including perforation, squeezing and use of casing patches or scab liners are not recommended as they do not provide long lasting results. In one of onshore fields in Saudi Arabia there is a persistent problem related to cementing at high pressure zones. Recently, communication between A (abnormally over pressurized zone) and B (low pressure zone) formations is occurring due to long term sea water injection with increasing frequency, and has resulted in production interruption in several wells. This paper addresses the problems through investigating field practices including drilling, cementing, and completion. It also reviews the field reports and cased hole logs. A three-month study was conducted to evaluate the effects of formation-A water on cement, where the cement was exposed to formation-A water under down hole conditions. The tests for permeability, mechanical properties TGA and EDXRF are presented, in addition to discussions of some of the preliminary findings.
Thaya, S. (Tokyo Institute of Technology) | Pipatpongsa, T. (Tokyo Institute of Technology) | Takahashi, A. (Tokyo Institute of Technology) | Doncommul, P. (Electricity Generating Authority of Thailand)
The large deposits of freshwater snail fossils aging around 12-13 million years has been discovered at Mae Moh lignite mine in the northern part of Thailand. The preserved area of snail fossils with layers of up to 12 meters deep in the mining area has been set aside; however, there is a concern about the influence of mining activities in the vicinity area as well as excavations at a deeper depth. Therefore, detailed studies of the strength characteristics of snail fossils become necessary. The present study reported part of an investigation program in which direct shear strength properties of snail fossils were focused through the direct shear test with constant vertical stress under wet and dry conditions. The intact and disturbed samples were collected from a subsurface of a location deposited outside the preservation area. The effects of vertical effective stress, water, overconsolidation, and multi-reversal shearing on the shear strength properties of snail fossils were examined. The results show that the stress ratio decreases with increasing the vertical effective stress and the number of shearing. The presence of water appeared to have an impact on strength properties to some degrees. In addition, there is a rise in the stress ratio as the overconsolidation ratio increases.
Two-dimensional numerical modelling of the influence of joint orientation on the Uniaxial Compressive Strength (UCS) of singly- and multiply-jointed cylindrical rock samples was performed using models with slenderness (length/diameter) values of 2 and 4. For steep joint orientations, the more slender models were found to produce smaller UCS values when compared to the less slender models in the case of the singly-jointed rock specimens. This observation was related to the need for more significant intact material rupture to accommodate sliding failure on the joint for the case of the less slender specimen models. When recommendations for specimen slenderness outlined in popular standards for UCS testing are adopted one should take care to ensure the slenderness values used do not place restrictions on the mechanisms by which failure can occur. Such restrictions are likely to cause overestimation of strength estimates for jointed rock obtained from UCS testing and could introduce significant risk in engineering design. No dependence on specimen slenderness was observed for the multiply-jointed specimen models. This appears to be related to the wider deformation zone available for sliding failure in the multiply-jointed models, which circumvents the need for significant intact material rupture in the failure process. The use of sufficiently slender rock specimens may not be required for realistic UCS values to be obtained for jointed rock in cases where the rock has multiple parallel joints and sufficiently small joint spacing.
A large carbonate oil field in Iran is suffering from severe casing collapses and related operational problems in salt layers of Gachsaran cap rock Formation. To investigate the causes and cures of operational problems, specifically casing collapse, knowing mechanical characteristics of salt layer of this Formation is a prerequisite. However, taking core in this Formation is very difficult bellow the depth of 300m due to high solubility and weakness of the rocks, therefore surface samples should be obtained to study the mechanical behaviour of this rock. This has risen the doubts on the validity of these studies when they are extended to higher depths where the tempreture is quite different from surface.
In this paper, a series of mechanical tests are performed on shallow depth salt rocks at different temperatures (23 °: C-100° C). It is found that the mechanical parameters have different reactions to changing temperature. It shows that compression and shear wave velocities, dynamic elastic, shear and bulk modulus decreases by increasing temperature. However, dynamic poisson ratio shows increase. Both uniaxial compressive strength and axial strain increase with temperature, whereas the tangent modulus Et goes to an opposite direction. Meanwhile, the plastic strain increases gradually and strain-softening behavior of the samples becomes increasingly evident. The relations between dynamic and static modulus at various temperatures are also investigated.