Schedule Session Details Expand All Collapse All Filter By Date All Dates Sunday, December 09 Monday, December 10 Tuesday, December 11 Wednesday, December 12 Filter By Session Type All Sessions General Activities Social and Networking Events Technical Sessions Panel, Plenary, and Special Sessions Energy4Me Training Course/Seminar Sunday, December 09 07:00 - 15:00 Field Trip: An Integrated Approach to Geologic Outcrops for Boosting Reservoir Understanding Jal Az Zor Escarpment, North of Kuwait City Ticketed Event Field Trip Jal Az Zor Integrated Field Course An Integrated Approach to Geologic Outcrops for boosting Reservoir Understanding When: 9 December 2018 Where: Jal Az Zor Escarpment, north of Kuwait City Organizers: KOC, with KOC and Shell SMEs The field trip will provide an integrated approach to geologic outcrops, using Jal Az Zor examples, that will trigger reflections in the participants about the implications of heterogeneities, scale, and 3D distribution of rock properties to models, studies, activities, and insights pertinent to reservoir analysis. The field course is specifically designed to relate the geology to a variety of subsurface disciplines involved in heavy oil development. Topics addressed will include baffles, reservoir modelling, steam conformance, cap rock integrity, well spacing, integration of well, reservoir, and facilities management (WRFM), and observation wells placement. The ultimate goals are to gain an appreciation for the value that the understanding of vital elements of rock description and sedimentology have for reservoir studies, and for the enhancement of production strategies. Group discussion will be encouraged to share knowledge and trigger new perspectives.
Arackakudiyil Suresh, Zac (Halliburton) | Kumar, Ajit (Halliburton) | Rondon, Leonque (Halliburton) | Pingle, Darshan (Kuwait Oil Company) | Al-Hindi, Khaled (Kuwait Oil Company) | Boushahri, Mohammed (Kuwait Oil Company)
Multilateral intelligent wells have been proven effective by both extending reservoir contact and providing proactive reservoir management. This paper highlights the lessons learned and critical well construction and completion steps that improve the efficiency of intelligent multilateral well drilling and completions operations. The case study outlines the successful completion of the third multilateral intelligent well in the Minagish field of West Kuwait.
The intelligent level 4 multilateral well was designed and drilled successfully. The sidetrack was performed using a specialized latch coupling that allowed for multilateral window cutting, orienting, and re-entry. The latch coupling was run in hole with the main bore casing, and a key orienting tool was used to confirm its orientation. Once the main bore was complete, a window was cut using a dedicated milling machine. Thereafter, a drilling whipstock was run with a window mill and watermelon mill to allow access to the lateral. This was followed by drilling the lateral section and running and cementing the liner. After the lateral section was drilled to the planned depth and cleaned out, the whipstock was retrieved. The intelligent completion installation consisted of a lubricator valve, two downhole permanent gauges, and two variable choke interval control valves.
The presence of surface-controlled, variable choke valves to control inflow from both the main bore and the lateral provides the capability to effectively manage the reservoir and production over the life of the well. This, in turn, prolongs the field life, thus improving overall economic performance and field economics. The case study well is the third multilateral intelligent well installed in Kuwait, and many recommended practices were implemented that allowed for improved efficiency and safety of the operation. Maintaining a clean well was emphasized as a top priority throughout the well construction process. The cement curing time was increased and the completion string was reviewed and redesigned.
This paper discusses the lessons learned and improvements made during installation of the third multilateral intelligent well. The steps performed during this operation have become the recommended practices for all upcoming intelligent multilateral well operations in Kuwait.
Cai, Mingyu (China University of Petroleum) | Su, Yuliang (China University of Petroleum) | Sun, Zhixue (China University of Petroleum) | Li, Lei (China University of Petroleum) | Yuan, Bin (University of Calgary)
The uncertainties of fluvial reservoir geologic model are notably high due to complicated geological conditions and unknown strong heterogeneity. However, previous uncertainty analysis approaches mainly focus on qualitative evaluation. In this work, we proposed a novel workflow to quantify and optimize the geologic model uncertainties using the virtual outcrops.
First, the 3D geologic model is built by the virtual outcrops and geology database is established by the fine description of modern sedimentations, geologic outcrops and dense spacing areas. Next, geologic modeling algorithm is optimally selected based on the complexities of target reservoirs, computational speed and the shape of sand bodies. In this work, three indicators are proposed to evaluate the accuracy of geologic models, including matching coefficient of digital grey images to virtual outcrops, consistency of braided stream facies morphology and connectivity of inter-well effective sand bodies.
For the braided channel in Sulige field examples, the width of channel belt is 1500~3500m and the average sand thickness is 5m. For channel bar, the width is 350~650m, the length is 800~1500m and the thickness is 3~6m. The virtual outcrops help determine the vertical sequence and planar characteristics of sedimentary facies and sand bodies. The comparisons between established model and virtual outcrops indicate that the accuracy of geologic models increases as the denseness of hard data becomes smaller and the optimal well spacing and row spacing match up with the sand body size and average well spacing of studied area. The evaluation system proposed in this work demonstrates the degree of geologic reproduction, reasonability and partial uncertainty of the models to the real reservoir.
The value of this work is to provide a novel practical approach to optimize and quantify the uncertainties of geologic model. Furthermore, the established workflow can further be applied to identify the most significant controlling factor to determine geologic modeling in unconventional reservoirs.
Al-Maqsseed, N. (Kuwait Oil Company) | Anthony, E. (Kuwait Oil Company) | Bhagavatula, R. (Kuwait Oil Company) | Rodenboog, C. (SHELL Kuwait EP) | Jamieson, Euan (Schlumberger) | Jha, Ajay (Schlumberger) | Hua, Gong (Schlumberger) | Al-Sharhan, Ghazi (Schlumberger)
The North Kuwait asset has several stacked producing reservoirs, further subdivided into multiple sub-layers, each sub-layer with substantial production potential. Over 75% of these sub-layers are depletion drive reservoirs requiring water injection for pressure support. Many existing/planned Injectors penetrated over- and under-lying layers that has good production potential. Similarly, many Producers penetrated adjacent reservoirs/layers that required injection support. With limited surface real estate available to accommodate the increasing demand for appropriately located Injectors and Producers, conventional single-purpose wellbores have become an unaffordable luxury.
An innovative concept was developed in-house by using a single wellbore for an unconventional dual purpose, namely, Simultaneous Injection
Due to the complexity and uniqueness of the SIP configuration, completing the Well on Paper (CWOP) sessions proved to be a very effective tool in the planning process of this completion.
The ESP Service Partner performed a System Integration Test (SIT) in a test well to verify equipment functionality and optimize the assembly procedure. Following the successful (SIT), the first installation was completed in early 2017. The systems installed to date were originally Producers that were ideally located for injection in an adjacent reservoir. The new Injection layer was stimulated initially, to assure maximum injectivity and longevity. The outer 5½" ESP Production string was run and landed first, followed by the inner 3½" string. The ESP’s were operated initially while the surface injection flow lines were fabricated and connected. Injection was then commissioned and monitored for inter-string communication. Initially, zero communication was observed with over 14,000 bwpd consistently injected over certain injection periods while maintaining original production rates. Evidence of possible leakage and inter-string communication was observed after seven (7) – eight (8) months of continuous injection. Investigations and analysis of integrity-longevity-failure to conclude root cause(s) and remedial solutions are still ongoing, where an upgraded design and improved operating procedures, shall be eventually formulated.
Previously only conventional dual parallel strings were deployed for Injection and Natural flow production. Now this unique and innovative design of Dual Concentric strings, first of its kind in the world, has raised the bar in the application of Simultaneous Injection and Production. This Workover-deployed completion eliminates the burdensome development costs of drilling new Injectors and Producers in this deep, multi-layered, stacked, depletion-drive reservoir environment. KOC has initiated a key technology that has significant global application, especially in offshore environments.
Channel sand reservoirs very rarely have layer cake geometries and are generally characterized by sand bodies/lenses with limited horizontal and vertical continuity. Significant lateral changes occur in reservoir thickness as well as reservoir properties and lenses are often stacked at different stratigraphic levels. The reservoir sands in the greater Burgan field show similar variations both structurally and stratigraphically. Navigating a wellbore in such complex channel sand reservoir requires precision geo-steering technology with two major requirements: Detecting reservoir boundaries with dip information for structural steering. Mapping multiple layers above and below the target layer for stratigraphic positioning. Detecting reservoir boundaries with information on layer dip and anisotropy can immensely help to forward plan trajectory as per formation changes and this require a good knowledge and study about the seismic data and offset wells information.
3D seismic data immensely help in placement of all kinds of wells, especially designing and fine-tuning a meticulous trajectory for Deviated and horizontal wells. Attributes made with seismic cube data, namely Structure and coherency volume, can image major to minor faults, which are generally viewed on slices of major formation tops. There are various other attributes like Impedance, Vp/Vs, Porosity and sand probability map, which can indicate possibility of sweeter part of reservoir. Depth of various major formation tops are predicted quite accurately within the limit of seismic resolution from Velocity model or Depth-Migrated seismic volume. These depth predictions immensely help in designing trajectory and landing the well in the actual desired zone of reservoir at the desired angle. During Geo-steering also, in spite of all the tools of drilling contractor at their disposal, the seismic data help to guide the drillers to steer in the right direction, if drilling team is out of track from the good part of reservoir.
Overlaying such a well in the seismic section directly gives the predicted depth throughout the well trajectory, which helps to design the Deviation survey parameters. The paper will explain a special attribute called Ant-trak, which not only shows the major faults, but also very minor faults and sometimes, fine geological features, which cannot be seen in seismic section or slices. This attribute is taken on Burgan-Third sand top surface. All the major NW-SE faults can be seen. Over and above, some minor faults are also seen in it. PSTM seismic data and the other structural attribute which able to show together, faults very clearly. Such a blended surface gives an enhanced display of faults in the area of study including very minor ones, which help to design the survey.
By using different Seismic Volume and Surface Attribute analysis, we mark the major faults trend and extracted many structural features in the study area. We try to deal with different attribute parameters and use offset wells data logs near to each planed horizontal well in the area which help us to have more control during geo-steering horizontal wells.
With the advent of new age real time drilling technologies, the amount of data generated downhole has increased tremendously. Complemented by superior telemetry, the ability to transfer data uphole has increased by many folds too. With the introduction of new generation geosteering and reservoir mapping applications, it is possible now to integrate conventional logs with deep directional electromagnetic resistivity and advance formation evaluation measurements for accurate bed mapping, real time assessment of reservoir quality, structural dip calculation and forward planning trajectory – all in an integrated and single platform. The result is informed decisions and highly optimized results. The paper will discuss on a case study using this innovative integrated platform where geologists, drillers and geosteering engineers worked in sync to come up with the best possible real time decisions for optimum well design and placement, in a clastic reservoir, reducing overall well construction risks and negotiating the challenges of undesired geological events like trajectory drilling through a fault.
The interpretation of deep directional electromagnetic propagation measurements via highly sophisticated inversion algorithms gives information on the spatial position of the wellbore w.r.t reservoir boundaries. The remote detection of boundaries up to 20 ft around wellbore, gives us the edge for trajectory forward planning by predicting upcoming structural trend, in other words called Proactive GeoSteering. Conventional logs combined with high end measurements like spectroscopy, sigma, source less density and neutron provide accurate real time formation evaluation while drilling which enhance decision making of geo-steering process. Availability of these high-end technologies would allow operators to place horizontal well as close as possible to top reservoir, optimizing long term well performance by minimizing attic oil and delay water production.
The case study represents how latest state of the art real time drilling technologies coupled with advance geosteering techniques successfully helped overcoming various geological uncertainties encountered while drilling a horizontal well. Unexpected minor sub-seismic fault was successfully mitigated which avoid undesired non-productive time and lost productivity of the well. The results were very encouraging in terms of well production, and optimum placement of the horizontal well which will enhance long term recovery.
This paper provides new insight on successful application of multi boundary mapping technique in optimizing well placement in top part of the reservoir and offers approach for drilling horizontal wells in similar case of complex clastic reservoir. The technique also discusses mapping of sub-seismic faults that cannot be identified by normal seismic data, and how to mitigate subsequent risk of the fault.
Dashti, Jalal (Kuwait Oil Company) | Al-Awadi, Mashari (Kuwait Oil Company) | Moshref, Moustafa (Kuwait Oil Company) | Shoeibi, Ahmad (Geolog International) | Pozzi, Alessandro (Geolog International) | Estarabadi, Javad (Geolog International)
The Middle Jurassic strata of the NE Arabian Plate compose part of the largest world-class petroleum system, with more than 250 billion barrels of proven hydrocarbons. The Najmah Formation, one of those productive strata located in Kuwait, represents a transgressive deposition within a deep basinal settings and anoxic environments; with its black shales interbedded with bituminous limestones the Najmah Formation works as both reservoir and source rock. Due to its organic richness and maturity, the middle Jurassic formation can be considered the best potential conventional/unconventional play in the Kuwaiti Province.
Evaporates of Gotnia, a HPHT formation overlaying the Najmah reservoir, are dealt with high mud weight (19-21 ppg), to counter the high pressured patches. The identification of Najmah stratigraphic top is crucial for setting the casing point, then reducing the mud weight for the final drilling phase. Missing this critical casing point may lead to several rig NPT and related operational cost increments, such as cement jobs and, in extreme cases, may lead to missing and abandoning the well. When the standard investigation methods, as the optical microscopy, or Gamma Ray failed in identifying the Najmah top, due to the similarity between its limestones and those of Gotnia Formation, the ED X-ray fluorescence (XRF) and X-ray diffraction (XRD) established distinctive formations geochemical ‘fingerprints’, as well as their sedimentary patterns, providing absolute certainties about the casing point position despite a misleading stratigraphy.
The technique of Chemostratigraphy, applied in this study on five exploratory wells, can increase the value of such geochemical fingerprints, providing not only applications as critical casing points ID but also a means to unify stratigraphic schemes, i.e. develop stable reference stratigraphic frameworks: changes in rock geochemistry reflect changes in the relative sea level, thus sediment supply/accommodation, oxygenation and diagenetic conditions.
Once inside the Najmah Formation, the elemental and mineralogical patterns point out different formation sublayers, corroborating many sedimentological and stratigraphic evidences obtained from outcrops and cores analyses. Some redox-sensitive trace metals are delivered to the sediment in presence of organic matter (Ni, Mo, V and U) under anoxic-euxinic conditions and tend to exhibit covariation with TOC, highlighting the best pay zones in the Najmah Kerogen sublayers. Some other metals such as Mn, Fe and Zn, in carbonate sequences, can evaluate the amount of carbonate cement (sparite) among the microcrystalline matrix (micrite); such metals, correlated with mud gas concentration, reveal the most porous sections within calcareous sublayers.
Having access to more detailed rock properties allow for one time decisions making, such as the identification of casing/coring points and the characterization of a reservoir in all its sublayers. Chemostratigraphy has led the operational team to minimize NPT and related costs, the completion team to the right well profiles and the production team to a better overview of the reservoir.
Al-Rushaid, Mona (Kuwait Oil Company) | Al-Rashidi, Hamad (Kuwait Oil Company) | Ahmad, Munir (Kuwait Oil Company) | Azari, Mehdi (Halliburton) | Hadibeik, Hamid (Halliburton) | Kalawina, Mahmoud (Halliburton) | Hashmi, Gibran (Halliburton) | Hamza, Farrukh (Halliburton) | Ramakrishna, Sandeep (Halliburton)
Reservoir relative permeability and capillary pressure, as a function of saturation, is important for assessing reservoir hydrocarbon recovery, selecting the well completion method, and determining the production strategy because they are fundamental inputs to reservoir simulation for predicting lifetime production of a well. Estimation of relative permeability and capillary pressure curves at reservoir conditions is also an important task for successful planning of waterflooding and enhanced oil recovery. The relative permeability and capillary pressure data estimated from core analysis might cause concern regarding representativeness, and adjustments are typically necessary for successful production forecasting. This paper proposes a new method to obtain relative permeability and capillary pressure curves with downhole pressure-transient analysis (PTA) of mini-drillstem tests (miniDSTs) and well log-derived saturations.
The new approach was based on performing miniDSTs in the free water, oil, and oil-water transition zones. Analyses of the miniDST buildup tests provided absolute formation permeability, endpoints of relative permeability to both oil and water, and curvature of the relative permeability data. Additionally, resistivity, dielectric, and nuclear magnetic resonance (NMR) logs were used to determine irreducible water, residual oil, and transition zone saturations. Combining these downhole measurements provided the relative permeability and capillary pressure curves.
Hadibeik, Hamid (Halliburton) | Azari, Mehdi (Halliburton) | Kalawina, Mahmoud (Halliburton) | Ramakrishna, Sandeep (Halliburton) | Eyuboglu, Sami (Halliburton) | Khan, Waqar (Halliburton) | Al-Rushaid, Mona (Kuwait Oil Company) | Al-Rashidi, Hamad (Kuwait Oil Company) | Ahmad, Munir (Kuwait Oil Company)
Reservoir relative permeability as a function of saturation is critical for assessing reservoir hydrocarbon recovery, selecting the well-completion method, and determining the production strategy. It is a key input to reservoir simulation for predicting lifetime production of a well. Estimation of relative permeability curves at reservoir conditions is also a crucial task for successful reservoir modeling and history matching of production data. The relative permeability data estimated from core analysis may cause concern regarding representativeness, and adjustments are typically necessary for successful production forecasting. This paper proposes a new method to obtain relative permeability curves with downhole pressure-transient analysis of mini-drillstem tests (mini-DSTs) and well-log-derived saturations.
The new approach was based on performing mini-DSTs in the free water, oil, and oil-water transition zones. Analyses of the mini-DST buildup tests provided absolute formation permeability, endpoints of relative permeability to both oil and water, and curvature of the relative permeability data. Additionally, porosity and resistivity logs were used to determine irreducible water, residual oil, and transition zone saturations. Combining all of these downhole measurements provided the relative permeability curves.
When multiphase fluids flow in a reservoir, the flow rate of each phase depends on the effective permeability of that phase (Alkafeef et al., 2016). Effective permeability is obtained from absolute permeability of a reservoir multiplied by the relative permeability. Although absolute permeability is a function of reservoir pore geometry and does not change with fluid type, relative permeability is a fluid-dependent parameter and mainly depends on fluid saturation, pore geometry, viscosity, and surface tension (Goda and Behrenbruch, 2004).
Al-Murayri, M. T. (Kuwait Oil Company) | Al-Mayyan, H. E. (Kuwait Oil Company) | Kamal, D. S. (Kuwait Oil Company) | Ziyab, D. K. A. (Kuwait Oil Company) | Chatterjee, M. (Tracerco Limited) | Hewitt, P. (Tracerco Limited)
A Miscible Hydrocarbon Gas injection pilot is being implemented by Kuwait Oil Company in the Minagish Middle Oolite (MN-MO) carbonate reservoir of West Kuwait. The water pre-flush phase of this pilot was initiated in March 2016 in preparation for subsequent miscible gas injection. An Inter-Well Tracer Test (IWTT) was performed during the water pre-flush phase to assess reservoir conformance and connectivity in a complex and highly laminated formation to support reservoir modeling activities.
Implementing an IWTT is an integral part of the overall surveillance/monitoring program to properly evaluate reservoir heterogeneities within and around the selected pilot area prior to miscible gas injection. Three different tracers were injected through the central injector into three geologically distinct, vertically stacked and inter-connected layers. Water samples were collected from three pilot producers on a regular basis for lab analysis to construct produced tracer curves. These tracer curves were then characterized analytically and compared with the original pilot performance forecasts that were generated using a reservoir sector model.
Tracer data showed reasonable breakthrough times and distinct peaks representing different flow paths for every injector-producer pair, involving one injector and three surrounding producers. Analytical interpretation of tracer data was useful to assess ultimate tracer production and swept volumes for each flow path. Based on the observed tracer breakthrough times during the water pre-flush phase, it can be inferred that limited preferential flow is expected during the subsequent miscible gas injection phase. The data from the above-mentioned IWTT and ensuing analytical characterization can be integrated with the on-going simulation activities to generate more reliable performance forecasts for miscible gas injection into the MN-MO carbonate reservoir.
This paper highlights how analytical interpretations can be derived for multiple flow paths in relation to water and miscible gas injection using IWTT data. The results from this study are important to enhance and fine-tune the reservoir simulation models that are being used in the meantime to generate reliable performance forecasts.