Al-Shammari, Asrar (Kuwait Oil Company) | Gonzalez, Fabio A (BP Kuwait) | Gonzalez, Doris L (BP America) | Jassim, Sara (Kuwait Oil Company) | Sinha, Satyendra (Kuwait Oil Company) | Al-Nasheet, Anwar (Kuwait Oil Company) | Datta, Kalyanbrat (Kuwait Oil Company) | Younger, Robert (BP Kuwait) | Almahmeed, Fatma (Kuwait Oil Company)
Magwa-Marrat reservoir fluid is an asphaltenic hydrocarbon, exhibiting precipitation and deposition of asphaltene in the production system including the reservoir rock near wellbore and the tubing. The main objective of this work was to optimize production in Magwa-Marrat wells by remediation of tubing plugging and formation damage. Well interventions were prioritized based on potential production benefit resulting from the removal of productivity impairment. It was required to understand current formation damage in all wells, including those without recent pressure transient analysis (PTA).
All PTA tests since 1983 for Magwa-Marrat reservoir were analyzed to determine the different reservoir parameters such as flow capacity (KH), Skin (S), reservoir boundaries, and the extrapolated reservoir pressure (P*). PTA derived permeability was compared to log derived permeability to quality control skin determination. Independently formation damage was estimated using the radial form of the solution of the diffusivity equation for pseudo steady state flow. Once a skin correlation for both PTA vs. Darcy's law equation was derived using out of date well performance, the formation damage for all wells was accessed using current productivity index to identify production optimization opportunities in wells without recent PTA. This work was combined with nodal analysis to separate vertical lifting performance and inflow performance relationship impact on total productivity detriment.
Cross plot of PTA derived flow capacity (Kh) vs. Log derived Kh correlates very well with a slope and a coefficient of correlation close to 1.0. This was observed for wells located in the reservoir where there are not heterogeneities near wellbore such as boundaries or natural fractures. For these cases the higher than normally observed estimated skin explained poorer well productivity. After skin values were accessed for all wells, a production gain was estimated, and the wells were ranked based on potential benefit. A stimulation campaign was put in place based on the type of rock, formation damage and vertical lifting performance. Eight (8) wells were stimulated and they delivered approximately an additional 20% production for the field.
This work was innovative in the sense that there was not pressure build up tests run prior to the interventions and such, there was not any production deferral. This was achieved by building the well performance understanding on a correlation that required petrophysical description, production rates and estimates of drainage area reservoir pressure.
Mauddud Formation is a major oil-producing reservoir in Raudhatain Field of North Kuwait. The Mauddud Formation is an early Albian in age and it was generated an environment of the shallow-water carbonate and consists of Grainstones, Wackestones and Mudstones deposited in ramp settings. In Raudhatain field (RAMA) is undertaking massive development efforts with planned enhancement in Oil production. Reservoir description and distribution of rock properties in 3D space are challenging due to inherent reservoir heterogeneity, in this case primarily driven by depositional and diagenetic patterns.
KOC North Kuwait Reservoir Studies Team (NK RST) has been challenged to increase the production from several key NK oil fields. To achieve this goal, KOC has partnered with Schlumberger to rebuild integrated model with Petrophysics, Geophysics, and Geology and Reservoir data of the Mauddud Reservoir. The original model was required to minimize challenges in new infill locations, increase Oil recovery factor and detect water breakthrough to minimize water production. One of the key issues in creating RAMA reservoir model is integration of all available data in identifying the horizontal permeability, reservoir heterogeneity and identification of thief zones.
A fine Geological grid model with 35M cells, 10 Geological horizons has been built to characterize the Mauddud reservoirs of the RAMA field including the permeability from PLT logs combined with petrophysical and lithological / facies data to add more understanding of the distribution of reservoir properties. Log response group methodology and the undeveloped area in the Saddle (structurally low area) has been modelled for the first time in Raudhatain NK Field. This combined study utilizes the available data and cutting-edge technology using Geo2Flow which resulted in fluid compartmentalization and free water level identification. STOOIP has been upgraded and unlocking potential in new segments of the developed field. The original model was built based on vertical/Deviation wells (345) which lead to discrepancies in the structural interpretation. The new update has been carried out including all horizontal wells to minimize the uncertainty in the structure framework.
Dashti, Qasem (Kuwait Oil Company) | Moosa, M.H. (Schlumberger) | Erdman, M. (Shell Kuwait Exploration & Production) | Jensen, P. (Shell Kuwait Exploration & Production) | Olusegun, Kolawole (Kuwait Oil Company) | Al-Qadeeri, Bashar (Kuwait Oil Company) | Dhote, Prashant (Kuwait Oil Company)
Kuwait Oil Company (KOC) is going through many new challenging projects that aim to increase its hydrocarbons production capacity by 70%. The North Kuwait Jurassic Gas Fields project is one of the key projects with unique challenges from the subsurface complex and challenging characteristics of deep reservoirs, high pressure high temperature (HPHT), high in H2S and CO2 concentration-to the design, construction and operating of surface facilities. The Gas Field Development (GFD) group was established in 2007 to manage and accomplish KOC’s desired objectives from the NKJ Gas Fields project. The new group had to recruit manpower and build the required technical skills to address the unique challenges. End of 2010, KOC-GFD entered into an Enhanced Technical Service Agreement (ETSA) with Shell in order to benefit from the International Oil Company (IOC) expertise. One of ETSA objectives is to develop local KOC staff through Knowledge Transfer, whereas challenge was more than 60% of the total GFD population were juniors, i.e. less than 4 years of experience.
The need to fast track the development of the new recruited staff was identified by the management as a critical key element to overcome the project complex challenges. The development of a new approach for staff development using the best of both worlds’ i.e. building on KOC’s training programs and supplementing with Shell Jurassic ETSA Knowledge Transfer resulted in the creation of the Technical Competence Ladder, TCL, framework for all GFD staff in 2017. This technical paper will describe how the Jurassic ETSA Knowledge Transfer progressed over the course of the contract; connected with GFD business objectives; used key methodologies for successful application in the day-to-day activities; promoted a performance-based learning environment; used critical resources with clear accountabilities; was monitored and measured continually; Implemented with structured approached.
progressed over the course of the contract;
connected with GFD business objectives;
used key methodologies for successful application in the day-to-day activities;
promoted a performance-based learning environment;
used critical resources with clear accountabilities;
was monitored and measured continually;
Implemented with structured approached.
The results include the development of Structure and detailed competence skills development program for main subsurface disciplines like: Reservoir Engineering, Petrophysics, Geosciences, & Petroleum Engineering. Each main discipline includes number of specialization and focused sub-programs. The TCL program was implemented, and the Knowledge Transfer are proven. The progress of junior staff competences has been tracked and measured over the years; the creation of motivated and competent workforce has resulted in improved performance and increased team productivity. The overall results reduced ‘existing’ competency gaps within the company, enhanced communication between junior and senior staff, improved staff confidence and work performance. Key examples of success will illustrate the points covered in the technical paper.
The Middle cretaceous Wara sandstone reservoir in Minagish Field is considered as highly heterogenetic sandstone which implying lateral facies extensive variations, stacked sand bodies with varying petrophysical properties. Several horizontal wells has been successfully drilled in lower part of Wara 6 sand channel, best thicker clean sand channel with very good oil production rate. Recently some wells have shown depleting of oil and increase water production. To develop such a challenging reservoir to maximize the oil production, a new plan has been developed to explore for new opportunities in Wara reservoir. The objective is to target different good stacked sand bodies in different Wara layers by drilling deviated wells. Some of old depleted Minagsih Oolite reservoir wells have shown good opportunities to sidetrack the wells into good Wara sand layers. This paper presents the integration between geostatistical models, well logs, well test results and different seismic elastic properties maps to identify best subsurface locations for drilling new deviated wells which combine the best quality sand bodies in different Wara layers. A few years ago geostatistical reservoir model along with core data and well log data were utilized to drill successful horizontal wells in W6 sand channels. However due to low resolution seismic data, Wara highly heterogonous lithology and uncertainty in geo-statistical model, it was challenging to continue identify good quality stacked sand bodies in different Wara layers without drilling unwanted silty sand or shale layers. Seismic inversion related elastic impedance data could discriminate between the good quality oil-bearing sand, shaly, and silty sandstones. Several old vertical wells that include good stacked sand bodies in different Wara layers; have been selected to validate the accuracy of elastic impedance maps along Wara layers.
Today, almost half of Western Canada's natural-gas production comes from the Triassic-aged Montney formation, a sixfold increase over the last 10 years while gas production from most other plays has declined. In the last few years, demand for condensate as diluent for shipping bitumen has driven development of liquids-rich Montney natural gas leading to a surge in gas production and gas-on-gas competition in the Western Canadian Sedimentary Basin (WCSB), which has driven local natural gas prices down. This has had a material effect on the operations and finances of companies active in the Western Canada and is reshaping the Canadian gas industry. A significant portion of this growth has taken place in NE British Columbia and with the planned electrification of the industry in British Columbia, including the nascent LNG operations, will influence tomorrow's power industry in this region. NE British Columbia is a geographically large area with sparse population and the power supply into this region has lagged behind development of oil and natural gas resources. The area was originally served from geographically closer NW Alberta. More recently, supply was established from the BC Hydro power grid with the most significant developments being Dawson Creek-Chetwynd Area Transmission (DCAT) completed in 2016 and the additional 230 kV transmission projects scheduled for completion in 2021.
Cudjoe, Sherifa (University of Kansas) | Liu, Siyan (University of Kansas) | Barati, Reza (University of Kansas) | Hasiuk, Franciszek (Kansas Geological Survey) | Goldstein, Robert (KICC - University of Kansas) | Tsau, Jyun-Syung (TORP - University of Kansas) | Nicoud, Brian (Chesapeake Energy) | Bradford, Kyle (Chesapeake Energy) | Baldwin, Amanda (Chesapeake Energy) | Mohrbacher, David (Chesapeake Energy)
The objective of this work is to conduct pore-scale analysis of the pore systems in an Eagle Ford (EF) outcrop sample and a Lower Eagle Ford (LEF) sample from a producing interval in the subsurface. After characterization, we estimate bulk transport properties (such as tortuosity and permeability) within each pore network model (PNM) using the lattice Boltzmann method (LBM). Comparing the two will evaluate the degree to which outcrop samples of the EF are or are not applicable analogs to the subsurface for laboratory-scale "huff-n-puff’ enhanced oil recovery experiments.
Grain types and pore systems of both samples were visualized and quantified at the micro- and nanoscale using scanning electron microscopy/backscattered electron microscopy (SHM/BSH), energy- dispersive X-ray spectroscopy (EDS), and focused ion beam-scanning electron microscopy (FIB-SEM). These methods measure mineral content, elemental (mineral) analysis, size distribution of pores and pore throats in addition to serving as the basis to develop pore network models (PNMs) for simulation. The LBM was then applied to the extracted pores to estimate permeability for each medium.
The 2D SEM/BSE/EDS images of the EF outcrop sample showed that the microstructure of finegrained inorganic matrix was modified by calcite neomorphic and passively precipitated microspar, spar, and pseudospar altering the texture of the depositional matrix, low clay content with some of feldspar, solution-enlarged microfractures, compactional fractures, coccolith debris, and calcite deformation (solution-enlarged cleavages). There are abundant microfossils including foraminifer tests ("forams") filled with either diagenetic calcite, quartz, organic matter or a mixture of these minerals; the organic matter in the foram chambers mostly show cracks/shrinkage pores or lack pores in organic matter.
On the other hand, the LEF reservoir sample showed significantly different diagenetic alteration with localized phosphate diagenesis, less calcite neomorphism, and better developed pores within the organic matter infilling the foraminiferal tests as well as in depositional kerogen embedded within the inorganic matrix. In addition, 3D FIB- SEM volumes showed the variation in tortuosity of each extracted PNM and its impact on the diffusion coefficient during gas huff-n-puff recovery. The LBM enabled the estimation of permeability at the molecular level from each extracted PNM.
Not surprisingly, the textural and compositional differences between the outcrop and subsurface samples lead to different PNM and different behavior in huff-n-puff experiments. This work bridges a gap in the literature by comparing and revealing the pore-scale heterogeneities of an outcrop sample to that of a subsurface sample to measure the impact of the underlying mechanisms associated with gas huff-n-puff recovery at the laboratory-scale, while estimating permeability within extracted pores with the LBM.
Reservoirs in the Barents Sea are several times shallower than in other parts of the NCS, essentially due to recent uplift and erosion of younger sediments. A proper understanding of their geomechanics is considered paramount for their successful development. In turn, the lack of any available analogue makes the proper in situ measurement of key parameters compulsory.
The paper describes the planning and execution of an appraisal well solely dedicated to the purpose of geomechanics data acquisition in the shallowest oil reservoir on the NCS – i.e. coring, logging, XLOT and injection testing. It focuses on the operations conducted in the oil reservoir itself, which included an entirely novel multi-cycle injection test aimed at estimating the large-scale thermal stress coefficient of the formations around the well – i.e. the impact of the injection temperature on the fracture pressure of the formations.
Every operation in the well was challenging due to the sea depth being about twice that of the overburden thickness and to the formations being quite consolidated, which was met by careful iterative multidisciplinary-planning. The equipment was often taken to its limit and sometimes extended beyond its standard use – e.g. the metering systems.
The injection test itself could not be performed traditionally – i.e. use of surface data and downhole memory gauge. Instead, the downhole gauge data were sampled, pumped out and transferred to a remote site where real time advanced analytics was used to ensure that safety criteria were always met throughout the operation in terms of vertical fracture propagation and lack of reservoir compartmentalisation. In addition, this allowed adjusting the planned injection schedule to the exact formation's response, which could not be fully quantified ahead of time.
All the targets of the appraisal well were met. The injection test – i.e. the shallowest on the NCS and perhaps worldwide in an offshore environment – was performed successfully. Its main results are considered essential for a possible future field development – e.g. the injectivity is confirmed and, in addition, a significant thermal effect is proven.
The series of novel technologies deployed in the extreme environment presented in the paper can easily and beneficially be extended to more traditional reservoirs. This concerns performing multi-cycle injection tests on appraisal wells on a systematic basis to prepare and optimise the development plan, real-time monitoring through advanced analytics and adjustment of these tests, start-up of injection wells during field development, monitoring and optimisation of water injection schemes, etc.
This paper outlines methods to characterize hydraulic fracture geometry and optimize full-scale treatments using knowledge gained from Diagnostic Fracture Injection Tests (DFITs) in settings where fracturing pressures are high.
Hydraulic fractures, whether created during a DFIT or larger scale treatment, are usually represented by vertical plane fracture models. These models work well in a relatively normal stress regime with homogeneous rock fabric where fracturing pressure is less than the Overburden (OB) pressure. However, many hydraulic fracture treatments are pumped above the OB pressure, which may be caused by near well friction or tortuosity but, may also result in more complex fractures in multiple planes.
Procedures are proposed for picking Farfield Fracture Extension Pressure (FFEP) in place of conventional ISIP estimates while distinguishing between storage, friction and tortuosity vs. fracture geometry indicators.
Analysis of FFEP and ETFRs identified in the DFIT PTA analysis method combined with the context of rock fabric and stress setting are useful for designing full-scale fracturing operations. A DFIT may help identify potentially problematic multi-plane fractures, predict high fracturing pressures or screen-outs. Fluid and completion system designs, well placement and orientation may be adjusted to mitigate some of these effects using the intelligence gained from the DFIT early warning system.
Al-Maqtari, Ameen N. (SAFER E&D Operations Company) | Saleh, Ahmed A. (SAFER E&D Operations Company) | Al-Haygana, Adel (SAFER E&D Operations Company) | Al-Adashi, Jaber (SAFER E&D Operations Company) | Alogily, Abdulkhalek (SAFER E&D Operations Company) | Warren, Cassandra (Schlumberger) | Mavridou, Evangelia (Schlumberger) | Schoellkopf, Noelle (Schlumberger) | Sheyh Husein, Sami (Schlumberger) | Ahmad, Ammar (Schlumberger) | Baig, Zeeshan (Schlumberger) | Teumahji, Nimuno Achu (Schlumberger) | Thiakalingam, Surenthar (Schlumberger) | Khan, Waqar (Schlumberger) | Masurek, Nicole (Schlumberger) | Andres Sanchez Torres, Carlos (Schlumberger)
A 3D petroleum systems model (PSM) of Block 18 in the Sab'atayn basin, onshore western Yemen, was constructed to evaluate the untapped oil and gas potential of the Upper Jurassic Madbi formation. 3D PSM techniques were used to analyze petroleum generation for conventional reservoirs and the petroleum saturations retained in the source rock for the unconventional system. Block 18 has several proven petroleum systems and producing oil and gas fields. The principal source rocks are within the Madbi Formation, which comprises two units, the Lam and the Meem members. Both contain transgressive organically rich "hot" shales with total organic carbon (TOC) of 8 to 10%; these are located stratigraphically at the base of each member. Additional organic-rich intervals within the Lam and Meem are less-effective source rocks, with lower TOC values.
The PSM consisted of 17 depositional events and 2 hiatuses. To accurately replicate geochemical and stratigraphic variations, the Lam and Meem members were further divided into sublayers. The model was calibrated to present-day porosity, permeability, and pressure data, and it incorporated vertical and lateral lithofacies and organic facies variations. Further calibrations used observed maturities (vitrinite reflectance and pyrolysis Tmax) and present-day temperatures and considered laterally variable heat flow from the Early Jurassic to the Late Miocene. Finally, petrophysical analyses from wells provided calculated hydrocarbon saturations, which were used to calibrate the saturation output from the model. The model satisfactorily reproduces the distribution of the main gas and oil fields and discoveries in the study area and is aligned with well test data.
Maturity results indicate that the upper Lam intervals currently sit within the main to early oil window but are immature at the edges of Block 18 (based on the Sweeney and Burnham Easy R0% kinetics). The lowest Lam unit enters the wet gas window in the center of the block. The underlying Meem member ranges from wet gas to early oil window maturity. Like the Lam, the Meem remains immature along the edges of Block 18. However, in the south of the block, the richest source rocks within the Meem are mainly in the oil window. The degree of transformation of the Meem and Lam varies throughout the members. The model predicts that, at present, the lowest part of the Meem, containing the greatest TOC, has 90% of its kerogen transformed into hydrocarbons.
The model confirms that the Madbi formation is a promising unconventional shale reservoir with a high quantity of hydrocarbons retained within it. Despite the higher quantity of hydrocarbons retained in the upper Meem, in terms of liquid and vapor hydrocarbons predicted in this model, the lower Lam is the most-prospective conventional tight sand reservoir, and the Meem has very small potential as tight sand reservoirs. This study provided a novel application of 3D PSM technology to assess new unconventional as well as conventional plays in this frontier area.
A. H. Khan, M. Faisal (Pakistan Petroleum Limited) | Abid, M. Faraz (Pakistan Petroleum Limited) | Fareed, Abdul (Pakistan Petroleum Limited) | Javed, Zeeshan (Pakistan Petroleum Limited) | Khan, M Noman (Pakistan Petroleum Limited) | Hashmi, Shariq (Pakistan Petroleum Limited)
Technical evaluation and subsequently devising an appraisal and development strategy of a structural cum stratigraphic reservoir based on a discovery well only is always challenging. The reservoir under discussion was discovered as a structurally bounded trap and the appraisal wells were drilled on NW-SE direction along with the main bounding fault based on this understanding. However, presence of hydrocarbon below the spill point, anomalous sand thickness, lateral facies and reservoir quality variations observed in few of the wells indicated stratigraphic component in the field. Further complexity was added when the deepest tested gas was assigned on the structural map which showed extension of the hydrocarbon play outside the block boundary where the area was under different operating company that later drilled multiple wells near the block boundary. Therefore, it was critical to estimate correct initial gas in-place and percentage distribution of hydrocarbon across the lease boundaries.
Well location map for the studied field
Well location map for the studied field
The objective of this paper is to present workflow that integrates multiple dataset to understand the field's hydrocarbon filling mechanism. Detailed geophysical and Petrophysical work has been carried out, which includes building of sequence stratigraphic framework, preparation of seismic attribute maps, understanding of the depositional setting for all the individual sand units encountered in all the wells, rock quality assessment (core and log methods with integration of capillary pressure curves), free water level (FWL) assessment, permeability modelling using machine learning approach (NN), pore throat radius estimation to relate hydrocarbon filling mechanism and saturation-height function modelling to build consistent 1D water saturation model.
Comprehensive dataset has been acquired to evaluate the potential of the field that covers 3D seismic for the entire field, biostratigraphic analysis for seven (7) well, conventional logs in twelve (12) wells and advance measurements like Elemental Capture Spectroscopy and high-resolution resistivity images in five (5) wells. Core analysis data also acquired in five (5) different wells including routine core analysis, capillary pressure measurements using high pressure mercury injections, pore throat radius, relative permeability measurements (Centrifuge), formation resistivity factor measurements and sedimentological analysis (XRD & thin section) to overcome the challenges and defining the uncertainty associated with initial gas in-place.
Sequence based boundaries were defined to correlate individual sand bodies using the core data, image logs, elastic logs, seismic transacts and attribute maps for understanding the depositional setting. Lat-er these correlations were used to build a consistent petrophysical model including VCL estimation from Gamma/Neutron-Density/Sonic Density methods which was validated with ECS/XRD data. Porosity model was developed and validated from the core porosity followed by variable "m" estimation from the porosity/m relationship using the SCAL data. Later on, the consistent water saturation (Sw) models were built for all the studied wells. Permeability models were built using Neural Network (NN) where core-based permeability used for calibration and the model was tested qualitatively with the mobility and the well test permeability. For the validation of Sw from the logs, capillary pressure-based flow units were built using FZI/RQI, Winland & BVW (log) methods to define flow units defined through the core data. It was observed that the Winland R35 method-based pore throat radius had good correlation with the Sw log. FWL from MDT to estimate the height of the gas column, Skelt Harrison equation to capture the shape of the capillary pressure curve and Swi from the Centrifuge analysis were used to calibrate MICP end point which helped in building consistent Saturation-height functions. Results showed good to excellent match from the modeled Sw (Pc) vs Sw(log).