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.
Rock mechanics tests on core from Early Cretaceous carbonate reservoirs from a super-giant field offshore Abu Dhabi has allowed definition of rock mechanical facies (RMF). Each of four RMF are based on stress-strain curves and associated strength and elastic parameters. The lab-based RMF correlate with mechanical stratigraphy classes previously defined from core (and that reflect visible differences in lithology and cementation). The RMF are correlated to reservoir zones and inter-reservoir, impermeable dense intervals, with three facies predominantly correlating with reservoir lithologies and one corresponding with primarily dense intervals. However, some reservoir zones, or sub-zones, can lie in more than one RMF. The RMF are, therefore, partly predictable: for any reservoir zone in the field prediction accuracy is to one or one of two RMF classes. This ambiguity is due to two factors: (i) lateral variation of RMF within some reservoir zones based on lithofacies; and (ii) continuity of mechanical properties between RMF classes. There is a change in RMF from crest to flank of the reservoir, as expected, but there is also local lateral variation within the crest of the field. The two RMF representing most of the reservoirs are expected to respond differently to field operations. Therefore, mapping lateral variation of RMF for some reservoir zones may provide a basis for implementing different reservoir management practices in different areas/zones of the field. The ultimate use of this information will be to enable full-field rock mechanics simulation of the reservoir to help understand the long-term effects of different production strategies.
Introduction & Background
The concept of mechanical stratigraphy is widely used, commonly to correlate fracture distribution and intensity to stratigraphy. The concept of rock mechanical facies (RMF) whereby a number of measured rock mechanical properties are correlated to stratigraphy is not new and is referred to in a number of papers, for example: Alhilali & Shanmugam (1991); Corbett & Friedman (1987); Yale & Jamieson (1994); McDermott et al., (2006); Khaksar, et al. (2009). However, RMF do not seem to be commonly used as a concept. We believe that characterising formations in terms of RMF has the potential to simplify characterisation for use for drilling; reservoir management; and history matching for simulation. In this paper we will describe how we have defined RMF for an oil-field and will discuss one way in which RMF could be used in the field.
The studied oil-field comprises a stack of limestone reservoirs separated by impermeable "dense?? limestone layers of Early Cretaceous age in a giant field located offshore Abu Dhabi (Figures 1 & 2). Production in the field has been by variably patterned water-flood over the last 30+ years. The dense layers measure up to a few tens of feet in thickness; the main reservoirs are up to 150 ft. The reservoirs are typically characterized by moderate to low matrix permeability, generally, but not exclusively, from 50 mD to 2 mD. Porosity is mostly in the range of 15-25%, more than half of which is microporosity. Depositional textures are predominatly wacke- to packstone with high-permeability streaks due to rudist and algal floatstone to rudstone and grainstones. Although intense bioturbation has destroyed most of the depositional textures, heterogeneities remain in some reservoirs in the form of dolomite-filled burrows, patchy/nodular cementation, stylolites and wispy solution seams, and fractures; all can occur as different layers within the reservoir. The reservoirs are not highly fractured although diffuse fractures are concentrated at the top and base of most reservoirs.
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 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.
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.
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.
Mustafa, Hanaey Dandarawy (Petroleum Development Oman) | Briner, Andreas P. (Petroleum Development Oman) | Jumaat, Mohd Shafie (Schlumberger) | Grove, Brenden Michael (Schlumberger) | Atwood, David C. (Schlumberger) | Judd, Tobias Conrad (Schlumberger)
Due to high global demand, easy oil production is no longer sufficient to meet the continuous requirements. Extracting oil by using enhanced recovery methods or from difficult environments poses many challenges that differ from one field or formation to another. Ultrahigh-strength formations present a particularly difficult environment. In addition to posing drilling challenges, such formations introduce significant challenges to completion operations—particularly perforating and hydraulic fracturing, which represent the critical final steps in establishing formation-wellbore communication.
A key perforating parameter is the perforation tunnel depth of penetration (DoP). A new paradigm of DoP modeling relies on shaped charge characterization in the laboratory under a range of rock strength and stress; however, most available data are for rock strength or unconfined compressive strength (UCS) values of less than 18,000 psi. Therefore, uncertainty exists regarding DoP in some Oman formations in which UCS varies from 20,000 to 55,000 psi. Two main phenomena need to be verified. First, because penetration is inversely proportional to UCS, extrapolation of the existing shaped charge performance data suggests that the penetration will be close to zero at this extreme rock strength. Second, characterization of the shaped charges under this new paradigm shows that a shaped charge that performs better in a weaker rock may not necessarily perform better in stronger rocks. Therefore, tests are needed to identify the optimal charge(s) in these very strong rocks.
With these objectives in mind, cores obtained from the ultrastrong Amin formation in Oman underwent laboratory testing. Performance results of a series of tests designed in general agreement with the procedures of the American Petroleum Institue Recommended Practice (API RP) 19B Section 2 exceeded expectation based on extrapolation of previously available laboratory data. These new data provide valuable calibration points for the penetration model in ultrahigh-strength rocks.
This paper presents the methodology, results, and observations of this test program and discusses the way forward, which should add value to perforation performance not only in Oman, but also worldwide in ultrahigh-strength formations. Although previous studies have briefly addressed high-strength formations, this is the first known work that systematically evaluates perforator performance in ultrastrong formations.