bluuebunny/crossref_metadata_2025 huggingface dataset:
Drilling Through Data: Automated Kick Detection Using Data Mining
Authors: Alouhali Raed , Aljubran Mohammad , Gharbi Salem , Al-yami Abdullah
Published: December 2018

This paper details using advancement in data analytics and the huge amount of data generated while drilling to develop an automated system to detect kicks while drilling. Detecting kicks in early stages gives the crew additional time to control it resulting in a safer and more efficient drilling operation. Five models were developed and evaluated to optimize kick detection they are: Decision Tree, K-Nearest Neighbor (KNN), Sequential Minimal Optimization (SMO) Algorithm, Artificial Neural Network (ANN), and Bayesian Network. The models were trained to detect kicks based on actual kick cases. The models are predicting kicks using only surface parameters such as: pressure gauges, flow meters, hook load, rate of penetration, torque, pump rate, and weight on bit. The performance of the five models is then evaluated and compared. Best two models were Decision Tree and K-Nearest Neighbor.
Implementing WRFM Well, Reservoir, Facility Management and Smart Field Best Practices for EOR Optimization
Authors: Zeidan A. A , Redha Reeham Ali , Williams Darryl D. , Montero Jacobo Enrique
Published: December 2018

Kuwait Oil Company (KOC) is operating two Heavy Oil fields. Field A aims at production by Cyclic Steam Stimulation (CSS), followed by steam flood. Field B envisages primary recovery through cold production, followed by non-thermal Enhanced Oil Recovery (EOR). This requires drilling and completion of large number of wells. Implementing Well, Reservoir and Facilities Management (WRFM) and Smart Field approach will be a key requirement for operation excellence in these fields.

Currently both fields have some wells in production, mostly as single isolated wells or wells in 5-acre/ 10-acre spacing. These pilot projects aimed at de-risking the commercial phase, which is to follow in the coming years. These wells are the training ground for young KOC staff to learn how to work in integrated teams using WRFM processes.

WRFM processes are tailor-made for KOC's operating environment. These processes include Digital Oil Field based on Exception Based Surveillance (to flag out only those wells and facilities outside of their operating envelope and/or optimization window) and Production System Optimization. This would help to eliminate operational bottlenecks, leading to optimization in manpower to deal with large number of wells. It is expected to be achieved by combining existing best practices of International Oil Companies (IOC) with existing KOC applications, leveraging successful global practices.

The paper shall highlight the timeline, activities and organizational changes underway to effect the transformation from existing operation to a larger and more complex development that includes continuous drilling, completion and well intervention (CWI) and facilities installation occurring simultaneously.

The implementation of WRFM Processes along with Digital field will achieve the production and operation goals by reducing well, artificial lift, and facility downtime. This innovative production optimization system by enabling efficient decision-making process shall lower the cost per bbl. and reduce down time by implementing automated surveillance workflow.
An Integrated Approach to Characterize Heavy Oil in Complex Clastics-A Case Study From Southern Part of India
Authors: Chakraborty Srimanta , Panchakarla Anjana , Deshpande Chandrashekhar , Malik Sonia , Singh Majithia Pritpal , Chaudhary Sunil , Murthy AVR
Published: December 2018

Conventional volumetric analysis has its own limitations & challenges to characterize fluid types in complex clastic reservoirs. Presence of shale and radioactive minerals in sandstones makes the evaluation more complicated compared to clean reservoirs as uncertainty become higher to ascertain grain density & total porosity. Delineation of pay zones (heavy oil bearing) & estimation of saturation become more uncertain due to reservoir complexities.

Elemental spectroscopy log can provide real time grain density, TOC (Total Organic Carbon) and mineralogy for complex reservoirs (radioactive sand). However, to determine the fluid type and porosity in this type of reservoir, Nuclear Magnetic Resonance (NMR) would be the best choice due to its capability of recording simultaneous T1 (Spin-lattice relaxation time) and T2 (Spin-Spin relaxation time) including diffusivity measurement sequences. Compare to the traditional 1D T2 spectrum based interpretation methodology; A new approach of using constrained 2D NMR inversion, enhances the capability to discern different fluid phases by mapping proton density as a function of T2 relaxation time (T2int) in the first parameter dimension and diffusion coefficient "D" (or T1 relaxation time or T1/T2app ratio) in the second parameter dimension. An integrated approach is used by combining NMR and Elemental spectroscopy results to reduce formation evaluation uncertainties in heavy oil reservoirs.

Successful integration of NMR, Elemental Spectroscopy Log with Image and Acoustic results helps to understand reservoir properties in study area. The advantage of using constrained 2D NMR over conventional 2D NMR reduces the uncertainty of responses between Clay Bound Water (CBW) and heavy oil, which has similar T2 relaxation mechanism. Integration of Clay volume from Elemental Spectroscopy measurements in constrained 2D NMR helps to differentiate the heavy oil and clay bound water responses. Furthermore, the combination of NMR & Elemental Spectroscopy results helps to segregate the existence of heavier oil & lighter oil components in the reservoir. Based on these results, potential hydrocarbon zones was identified and successful testing attempts were made.

This paper shows an approach of using constrained 2D NMR results over conventional 2D NMR to overcome reservoir uncertainties & to identify potential pay zones.
Risk Assessment in Sand Control Selection: Introducing a Traffic Light System in Stand-Alone Screen Selection
Authors: Mahmoudi Mahdi , Fattahpour Vahidoddin , Velayati Arian , Roostaei Morteza , Kyanpour Mohammad , Alkouh Ahmad , Sutton Colby , Fermaniuk Brent , Nouri Alireza
Published: December 2018

Sand control and sand management require a rigorous assessment of several contributing factors including the sand facies variation, fluid composition, near-wellbore velocities, interaction of the sand control with other completion tools and operational practices. A multivariate approach or risk analysis is required to consider the relative role of each parameter in the overall design for reliable and robust sand control. This paper introduces a qualitative risk factor model for this purpose.

In this research, a series of Sand Retention Tests (SRT) was conducted, and results were used to formulate a set of design criteria for slotted liners. The proposed criteria specify both the slot width and density for different operational conditions and different classes of Particle Size Distribution (PSD) for the McMurray oil sands. The goal is to provide a qualitative rationale for choosing the best liner design that keeps the produced sand and skin within an acceptable level. The test is performed at several flow rates to account for different operational conditions for Steam Assisted Gravity Drainage (SAGD) and Cyclic Steam Stimulation (CSS) wells. A Traffic Light System (TLS) is adopted for presenting the design criteria in which the red and green colors are used to indicate, respectively, unacceptable and acceptable design concerning sanding and plugging. Yellow color in the TLS is also used to indicate marginal design.

Testing results indicate the liner performance is affected by the near-wellbore flow velocities, geochemical composition of the produced water, PSD of the formation sand and fines content, and composition of formation clays. For low near-wellbore velocities and typical produced water composition, conservatively designed narrow slots show a similar performance compared to somewhat wider slots. However, high fluid flow velocities or unfavorable water composition results in excessive plugging of the pore space near the screen leading to significant pressure drops for narrow slots. The new design criteria suggest at low flow rates, slot widths up to three and half times of the mean grain size will result in minimal sand production. At elevated flow rates, however, this range shrinks to somewhere between one and a half to three times the mean grain size.

This paper presents novel design criteria for slotted liners using the results of multi-slot coupons in SRT testing, which is deemed to be more realistic compared to the single-slot coupon experiments in the previous tests. The new design criteria consider not only certain points on the PSD curve (e.g., D50 or D70) but also the shape of the PSD curve, water cut, and gas oil ratio and other parameters.
Satellite INSAR Technology for Cap Rock Integrity Monitoring of CSS and SF Heavy Oil Production Kuwait
Authors: Ren Zu Biao , Al-Rabah Abdullah Akarim , Bansal Prashant , Freudenreich Yann , Rawnsley Keith , Zhang Ian
Published: December 2018

Kuwait Oil Company (KOC) is developing its shallow heavy oil field using thermal method. Top risk of this project is the cap rock failure. If failure occur, it may lead to the steam leakage, overlying aquifer contamination, ground heave or subsidence and surface collapse. For the monitoring ground deformation caused by cyclic steam stimulation (CSS) and steam flooding (SF) thermal operation in Kuwait, InSAR technology is being considered. Interferometric Synthetic Aperture Radar (InSAR) is a remote sensing technique to measure surface heave and subsidence.

First stage of heavy oil thermal development in North Kuwait comprises production from shallow Miocene reservoirs covering an area of roughly 30 square kilometers, by two or three cyclic steam stimulation (CSS) process followed by steam flooding (SF) process. Main reservoirs are the shallow Tertiary un-consolidated sandstone within the measured depth of 650 to 750 feet, sealed off by Up Shale layer that is about 30 FT thick. High pressure and temperature steam will be injected to reservoirs zones, which could result in cap rock breach causing surface heave or subsidence. High-precision and frequent measurements of surface deformation is very important for the study of cap rock integrity.

With the advancement of InSAR technology, millimetric precision of ground deformation measurement is possible. The important factors affecting measurement accuracy of ground deformation is Radar microwave length. The most common of microwave is the L band with 24 cm wavelength, the C band with 4-8 cm wavelength and the X band with 2.5-4 cm wavelength. The choice of wavelength influences the precision. However, there are some other factors which have impact on measurement quality such as spatial density of the measurement points, climatic condition, distance between the measurement points and reference points, number and temporal distribution of acquisitions.

InSAR technology is expected to provide regular surface deformation maps during heavy oil production to monitor the cap rock integrity and to optimize wells and reservoir management. This technology has many benefits, such as reliability, simplicity, low cost, weather independent, minimal field intervention and ability to acquire at night. The absence of vegetation growth in our field area makes this technology very effective. To increase the frequency of data collection and to improve the accuracy of the deformation maps, satellite ascending and descending images are also used. Use of ascending and decending images helps in calculating the vertical and horizontal deformations from the Line of Sight (LOS) measurmemnts.
Hot Dry Air Diffusion HDAD Technology for Lower Fars Heavy Oil
Authors: Al-Bazzaz Waleed Hussien , Abdullah Laila Adnan , Qurban Anfal Naser , Al-Shatti Sharifa Abdul-Samad
Published: December 2018

Lower Fars heavy oil <16 °API is considered a type of conventional heavy oil, which will be considered as priority petroleum production system for future heavy oil recovery in Kuwait. These types of oils are abundant in great amounts in Ratga field North Kuwait, yet expensive to produce due to its high viscosity hence low mobility underground. Kuwait strategy is shifting focus to these types of oils since conventional medium oil and other less-quantitative-light-oil reservoirs are continuously depleting. The study's interest is directed towards a specific type of EOR oil, which is hot dry air sequestration into Lower Fars heavy oil. This study presents novel heavy oil recovery method for 14 °API crude oil using hot dry air as well as their potential recoveries. All recoveries considered for this study are bench-scale laboratory physical experiments with horizontal (0 °), vertical (90 °), and directional (45 °) continuous air diffusion augmented with applied different thermal heat treatments.

The main objective for this research is to model recovery efficiency from this hot dry heat diffusion technique (HDAD). This technique will produce air diffusion design. This design will consider direction of blow diffusion for three possible well orientations: horizontal 0 degrees, vertical 90 degrees, and directional 45 degrees. Also, the design will consider six temperatures: 27 °C 30 °C 60 °C 70 °C 85 °C and 100 °C dry hot air diffusions. Moreover, the design will consider two diffusion velocities 74.08 km/hr and 111.12 km/hr. These velocities will determine designing the time of recovery, which is one hour, according to lab-time limitations and permissions. The main technology motivation for hot dry air diffusion (HDAD) research is finding the optimized economical EOR recovery efficiency factor that will extract most of 14 °API Lower Fars oil. The model determines the recovery potential factor in a classic, optimum and conventional economic scenario considering the energy usage to generate the hot dry air delivered to the reservoir. Also, HDAD technology usages will avoid the use of water technologies recoveries. Avoiding water technology recovery will minimize environmental impact, crude oil/ emulsions subsurface-mobility issues and costly water production management used at current steam economic challenges.
Engineered Hybrid Drill Bit Technology Doubles Drilling Performance in Impact-Prone Carbonates Heavy Oil Application
Authors: Agawani Waleed , Al-Enezi Dakhil R. , Pandya Mehul , Gupta Pravind , Abdelhamid Atef , Al-Habib Hamad , El-Touny Shrief , Ahmed Tausif , Mohammed Jassem A.
Published: December 2018

Optimised drilling performance requires matching the right drill bit technology to an application, which can be an engineering challenge. Hybrid bits provide versatility in drill bit selection that was previously not possible with conventional drill bit technology, allowing for a broader range of applications. This paper details the results of a case study where polycrystalline diamond compact (PDC), tungsten carbide insert (TCI) and hybrid bits were tested in the same application in an attempt to improve drilling performance.

Each drill bit type has its strengths and weaknesses, and is therefore suitably matched for specific applications. Sometimes, a specific technology matches well to the application, and it is the ideal solution; however, there are many cases where the ideal drill bit type isn't so clear. Hybrid drill bit technologies produced a new generation of bits. These bits reduce the difference between specific bit technologies, enabling them to outperform either type in demanding applications that require strengths from each technology to drill successfully.

A non-homogeneous carbonate formation that was prone to causing impact damage challenged conventional drill bit technologies. The 12.25–in. hole section was drilled vertically on a rotary bottom hole assembly (BHA). Initial trials with PDC bits showed that the bits suffered significant impact damage, preventing them from completing the section or reducing their drilling capacity so the rate of penetration (ROP) dropped below TCI performance. The TCI bits drilled relatively slowly, and although they were more durable, they also suffered impact damage.

Hybrid bits were tested on this project to leverage the benefits of each technology and improve drilling performance in this section. This hybrid technology achieved outstanding results in the South Ratqa field. In multiple deployments the hybrid drill bit doubled the ROP compared to conventional technologies. The benchmark performance reached by the hybrid drill bit was triple the ROP of conventional technology. The trial saved the operator up to 3.5 drilling days and more than 70% of the drilling cost for this section.
Investigation Wettability Contact Angle Measurement in Kuwaiti Heavy Oil Reservoir and Modeling Using 2D Imaging Technologies
Authors: Al-Bazzaz Waleed , AlMuddhhi Salah , AlOstath Mohammed
Published: December 2018

Wettability contact angle characterization will be investigated by 2D technologies and a deterministic model is developed. Deterministic approach is a robust technique using 2D image capturing and image analyses that are applied on a Kuwaiti silty sandstone reservoir to accurately quantify, mathematically as well as physically, wetting contact angle trends in the rock sample. And, then, generate all possible pore contact angles. Wettability contact angle quantification utilizes imaging method and recovery model with deterministic systems is a novel approach. Prediction of recovery schemes is crucial for reservoir development and management. Since contact angle initial state is captured and well described, measurement will no longer be random or follow stochastic solution. In this study, heavy oil recovery prediction model is also developed by constructing mathematical model based on statistical grouping and averaging for all measured pore-walls available in the rock sample. Pore parameters such as pore-area, pore-count, and pore-wall and pore shape distribution are all captured and measured experimentally and data can be accurately generated. Previously, contact angle is always based on linear assumptions and its direct quantification is vaguely established. In this study, quantifying wetting contact angle follows morphological approach that has greater confidence.
Polymer Field Development with a Strong Bottom-Up Aquifer in a Field in the South of the Sultanate of Oman
Authors: Alkindi Abdullah , Jabri Reham , Mjeni Rifaat , Gharbi Mohammed
Published: December 2018

Full field polymer flood has been identified as a potential EOR process for a heavy oil field with a strong bottom aquifer in the South of the Sultanate of Oman. A number of surface and subsurface risks have been identified prior to field implementation, including matrix injectivity, polymer sweep and impact of back produced polymer on surface facility & the field wet lands (reed beds). The development of the field will take a place in a phased manner in order to reduce the capex exposure, maximize the utilization of existing facility and managing project risks while contributing to the overall production. In order to support the standardization and steer the future phases the modular facility concept was selected as basis for polymer preparation and injection facilities, this design was made flexible enough to cater for a wide range of possible trial outcomes.

A very comprehensive polymer pilot was performed in this dome-shaped heavy oil reservoir to assess polymer sweep performance as well as losses to the strong water aquifer. An inclusive real-time surveillance programme was executed to monitor key parameters including pressure, injection/production rates, viscosity and water quality, which concluded incremental oil gain from the process. Other tests were conducted to assess the impact of back produced polymer on growth of plants, heater fouling and surface facility separation tanks. In general, all results were positive which paved the way for field-wide development of polymer flooding with less Capex requirement.

A sustained incremental oil gain was clearly observed from polymer injection, which was supported by saturation logs acquired from the observation wells. Injectivity could not be maintained as planned, due to a combination of polymer, biological and water quality issues. Later tests including biocide injection and QA/QC of polymer batches as well as some well stimulation did show improved injectivity profiles. Demulsifier tests mitigated the risk of creating stable emulsions. Lab tests indicated no heater fouling observed below 150°Cdeg. Short and long term investigation into the impact of water-contaminated polymer on plants in the wet lands was positive with the plants showing no necrosis with back produced polymer concentrations up to 500 ppm which is achievable given the excessive amount of water received at the facility level that dilute the back produced polymer. This helped in making the project more economically attractive as it results of a saving of around 30% from the overall project Capex.

The different surface and subsurface tests paved the way for a full field implementation of polymer injection in structures with strong bottom water aquifer. The paper discusses the phasing that was purused to mitigate risks, learn on the go and improve the project economics
Experimental Study on the Matching Relationship between PPG Size and Reservoir Heterogeneity
Authors: Wu Dejun , Zhou Kang , An Zhibin , Hou Jian
Published: December 2018

Preformed Particle Gels are successfully used for profile control in heterogeneous reservoirs. However, it is still unclear how to select proper PPG size for a given heterogeneous reservoir. In order to obtain the best profile control performance, it is necessary to study the matching relationship between the PPG mesh and the permeability ratio.

In this paper, the heterogeneous parallel-dual-sandpack experimental setup is established, including the injection system, measurement systems for temperature and pressure. During the experimental processes of water injection, PPG injection and subsequent water injection, the fractional flow of the two sandpacks with high and low permeability are recorded respectively. Then, a quantitative characterization parameter of the profile improvement ability is defined by dividing the change of fractional flow of the low permeable sandpack before and after PPG injection by that of low permeable sandpack before PPG injection.

The experimental results show that different PPG meshes will achieve different profile control performance for the heterogeneous sandpack with the determined permeability ratio. The PPG with excessive large size may block the low permeable area, decrease its fractional flow and thus cause more severe flow heterogeneity. The PPG with excessive small size can not well block the high permeability area and they can migrate out during subsequent water injection resulting in the increase of fractional flow in high permeable area again. The matching relationship analysis show that the matched PPG mesh increases as the permeability ratio of the heterogeneous sandpack increases. In detail, the matched PPG sizes for the permeability ratio of 2, 4, and 6 are 120-150 mesh, 100-120 mesh and 60-80 mesh, respectively.

The paper studied the matching relationship between PPG size and permeability heterogeneity, which was beneficial for selecting the proper PPG size for different heterogeneous reservoirs in more future applications.
Spatial Distribution of Clay Minerals in the Neogene Sediments of North Kuwait and its Impact on Thermal Production
Authors: Mishra Prasanta Kumar , Ahmad Khalid , Al Khandari Jassim
Published: December 2018

Clay minerals are commonly observed in the Neogene succession of North Kuwait, both in the two viscous oil rich sandstone reservoirs (S1, S2) and intervening shale layers. SEM and XRD analysis of the core samples explain that Smectite is the dominant and Palygorskite, Illite and Kaolinite as minor clay mineral constituents. The paper describes the vertical and lateral distribution of these minerals in different sedimentary facies from bottom to top and the impact of steam on them.

The bottom and second channel-dominated sand and intervening shale (S2B sand, S2 Shale, S2A sand) layers show variation in total average clay content, as well as the swelling clay (smectite, illite-smectite) and fibrous palygorskite, with a low content in the north and center (2-4.6%), a moderate content in the east (6.7-7.3%) and a high content in the south (11.2-14.4%).

The Middle shale layer (MShale), is recognized as a flooding surface, observed at base of muddy interdistributory bay/lagoonal or floodplain deposits, sharply overlaying the channel-filled sandstones. Smectite –Illite is the dominant clay constituent.

The first channel-dominated sand and intervening shale (S1B sand and S1 Shale) layers contain predominantly smectite, illite-smectite and palygorskite content. The northern, southwestern and southeastern parts of the field, with more argillaceous channels and floodplain facies associations, have a high average total clay content (9.6-20%). The central part of the field, which is predominantly contains clean channel sand bodies, has a lower, average total clay content (4.9-12.6%).

The topmost sand (S1A sand) layer contains higher proportion of muddier channels and interdistributary bay facies, in the northern part and has high (>7%) total clay content, but generally <2% swelling clays and palygorskite. The central part of the field, with clean channel sands, has relatively low (<7%) total clay content, with 0.8-3.2% swelling clays and palygorskite. The southern part of the field, with argillaceous channels, has a relatively high (>7%) total clay content, with 2.2-6.3% swelling clays and palygorskite.

The sealing Cap Shale (bound by maximum flooding surface at the base and an erosive surface at the top) comprises of marine and restricted marine shales capping the underlying S1A sandstones. The clay mineral comprises of illite-smectite, kaolinite and chlorite, with no palygorskite content,

As this viscous oil is planned to be produced by thermal applications, Clay stabilization experiments were conducted to ascertain the permeability reduction in the reservoir due to swelling of clay minerals and changes after exposure to steam. The steam flood experiments are conducted at 32, 65 and 232°C on actual core plugs and the conversion of Illite-smectite to smectite was observed, reducing the permeability. Chemical stabilizers were suggested for controlling these damaging effects at higher temperature.
Waterflood Study of High Viscosity Saturated Reservoir with Multiwell Retrospective Testing and Cross-Well Pressure Pulse-Code Testing
Authors: Aslanyan Artur , Kovalenko Igor , Ilyasov Ilnur , Gulyaev Danila , Buyanov Anton , Musaleev Kharis
Published: December 2018

A waterflood study has been performed on a high viscosity saturated oil deposit with bottom water aquifer and complex geometry driven by regional tectonic stress and numerous shale breaks. The commercial production is on-going for the last 2 years with medium length (1,000 m) horizontal wells and start facing formation pressure decline.

The foremost challenge was to check if injection pressure is transmitted through the oil pay without leaking into the bottom water aquifer. The next question was whether the full net pay is engaged in pressure support under water injection. The last question was to check on permeability anisotropy.

The transmissibility between wells have been assessed with multi-well retrospective testing (MRT) of permanent downhole gauges (PDG) historical data records which are a part of standard ESP telemetry. The fluid mobility and hydrodynamic average thickness between water injector and oil producers have been estimated with cross-well pulse-code pressure pulsations (PCT) based on pre-designed rate variation sequence [1 – 8]. The pulse-code sequence was designed in full-field 3D dynamic model to ensure capturing response in two contrast scenarios: with pressure propagating via aquifer and via oil pay, which have a high degree (30:1) of fluid mobility contrast. The data processing and interpretation was performed in PolyGon™ software [18] using the pulse-code decomposition for PCT tests and multi-well deconvolution for MRT tests.

The cross-well mobility in injector-producer pairs from PCT was indicating that pressure was fairly propagating via oil pay. The effective thickness of PCT-scanned area turned to be in-line with net oil column thickness from 3D geological model.

The MRT-scanned area was showing much lower transmissibility than 3D geological model prediction which was interpreted as the most part of the oil pay in this area has intermittent connectivity due to severe shale breaks development. This gives strong indication on searching the way to commingle production from isolated reservoir elements in this area [8 – 14].

The areal analysis of permeability in PCT-scanned and MRT-scanned areas has indication for 1:2 permeability anisotropy transversal to the regional stress direction which should be reconfirmed by a dedicated study.
Integrated Petrophysical Evaluation of Tayarat Formation for Water Disposal Purpose
Authors: Taqi Fatma , Ahmed Khalid , Saika Pabitra , Tyagi Aditya , Freeman Michael , Ren Zubiao , Zhang Ian , Muhammad Diri , Warrlich Georg , Al-Rabah Abdullah
Published: December 2018

A heavy oil field in Northern part of Kuwait has developed which requires appropriate disposal of produced formation water. Some important questions for water disposal well planning include: Where to inject?Where to inject?What is the maximum operation pressure (MOP)?How far away the disposal wells should be spaced?How much water can be inject in each well?

Integrated subsurface evaluation performed to address above questions. Seismic data provide a good overview lof the structuration and imporatant insight where sweet spots for injection may be found. Wireline logs and core information are used to derive petrophysical properties, characterize fracture, and gather geomechanical information. Injectivity tests established the injection rate and confirmed the estimated minimum horizontal stress. Analogue water injection data from nearby fields are used to provide information on the dynamic behavior of the reservoir, to reduce uncertainties owing to the limited injection rate data available.

The integrated analysis of the relevant, available subsurface data reveals that the Tayarat formation has significant variations in lithologies, mineralogies, and mechanical properties. Important information such as the receiving zone thickness, fracture orientation, injection rate, and storage capacity have been derived. Based on this information, we have made important recomemndations on disposal well spacing and maximum operational operating pressure (MOP).
Petrofacies Classification Method for Enhanced Reservoir Characterization in a Complex Highly Heterogeneous Shallow Unconventional Reservoir in Northern Kuwait : A Case Study
Authors: Choudhary Pradeep , Freeman Mike , Al-Boloushi Ahmed , Benham Philip , Sakia Pabitra , Tyagi Aditya , Ahmad Khalid , Jha Madan , Zhang Ian , Warlich Georg , Al-Rabah Abdullah
Published: December 2018

Objectives/Scope

The shallow depth unconventional reservoir in Northern Kuwait is essentially a monoclinal structure. Sediments have undergone significant shallow depth diagenesis, which resulted in selective oil/water accumulation, controlled mainly by lithological variations. Thus, the reservoir can be classified as stratigraphic-dominant trap. A correlation approach required addressing these variations, which can also be well understood by non-geologist, and the scheme should be appropriate for selection of perforation intervals.

Methods, Procedures, Process

Reservoir sands are in the form of multi-stacked distributary/fluvial channels. Subsequent to sediment deposition, moderate to intense diagenesis took place. The diagenesis resulted in formation of cemented baffles under low reservoir pressure (250psi) regime. For demarcation of bed boundaries, mapping and modelling purpose the reservoir sand, shale, baffles, gas, water, water above oil, this petrofacies classification method is proposed. The method is well capable of defining the various bed boundaries with fluid/gas content in it with confidence. The method developed after extensive core, core data and log calibration and study. More than one thousand wells correlated.

Results, Observations, Conclusions

The classification method is simple, yet robust to characterise reservoir vs. non-reservoir variations and oil/gas vs. water quite effectively. Cementation activities typically noticed on top/bottom of the units but many times in between the reservoir sand also. We are able to correlate cemented layers across the area. The cementation also gives rise to water perched above oil phenomenon due to relatively higher capillary pressure in the zone. Oil is migrated post-cementation and occupied reachable pore spaces. Oil also has undergone significant biodegradation because of favourable temperature and restricted nutrient supply. As a result, thin layers of thermal/biodegraded gas also formed locally. The method allows for surface related categorisation representing clean sand, cemented sand, shale, gas/oil/trapped water zones.

Novel/Additive Information

This unconventional reservoir is being developed with thermal application. Thickness of baffles, barrier, gas, water zones are critical in selection of perforation interval for steam application. This classification method is part of perforation selection for first phase of development and modelling purpose, and it was applied to hundreds of wells, many of them are undergoing production operations successfully.
Fluid Contact Identification for a Heavy Oil Shaly Sand Reservoir with a Biodegraded Oil Column
Authors: Battashi Fathiya , Khattak Ali , Svec Robert
Published: December 2018

This paper reviews the fluid contact analysis of the Marmul Gharif South Rim (MM GSR) heavy oil field in the South of the Sultanate of Oman. The field is highly compartmentalized by several faults into 17 blocks in total with a large variation in well density within those blocks. The reservoir in this field is the shaly-sand Gharif formation, in which the Middle and Lower Gharif are separated from each other by either a paleosol or competent shale. The hydrocarbon in these sands has an observed viscosity variation as a function of height above free water level (HAFWL) due to biodegradation. This variable viscosity has been observed in a large number of oil samples with higher viscosity close to the oil-water contact (OWC). The sands tend to be vertically discontinuous in the wells, so that direct observation of the OWC on logs is very rare, causing most well logs to yield only water up to (WUT) or oil down to (ODT). Accurate pressure gradients are difficult to obtain due to the low density contrast of heavy oil against the fresh formation water. Consequently, the OWC is not readily identified in certain blocks. This has resulted in either over-estimating oil volumes when substituting WUT or under-estimating volumes when substituting ODT in specific blocks of the field. In addition these cases also result in a lack of reliable constraints for estimating high and low case oil contacts.

Methods, Procedures, Process

A viscosity based approach was used to overcome gaps in the fluid contacts data-set and provide essential information for future field development. The approach utilizes the viscosity data in each block to determine representative base case contact along with shallow and deep cases. The results of this analysis were confirmed by production data and are consistant with the ODTs from horizontal wells.

The resulting fluid contact is then used as an input to the saturation height function which is used later as an input to calculate in-place volumes.

Results, Observations, Conclusions

Viscosity based contact provides a more robust fluid contact definition in areas where traditional methods resulted in data gaps. The paper presents a detailed methodology of this approach.

Novel/Additive Information

The results of this work are an essential component of optimizing the understanding of the fluid contact in the field, which helps to develop the field efficiently by drilling the oil producers and water injectors in more optimum locations.
Production Optimisation of Heavy Oil Wells Using Autonomous Inflow Control Devices
Authors: Moradi Mojtaba , Konopczynski Michael , Mohd Ismail Ismarullizam , Oguche Iko
Published: December 2018

The uneven distribution of the production influx from the reservoir into the wellbore has been identified as the main issue in the management of production in heavy oil wells. This occurs due to a drastic difference between the mobility of oil and water i.e. water flows faster than oil in these reservoirs. This can be exacerbated by reservoir heterogeneities resulting in very high water production rate requiring large water treatment facilities which may be limited in offshore developments, resulting in reduced oil production.

Advanced well completions utilizing Inflow Control Devices (ICDs) and Autonomous Inflow Control Devices (AICDs) have proven to be robust solutions for these problems. Both devices help to enhance the performance of heavy oil wells by delaying the water production, however, AICDs are more capable to reduce the water production and increase oil production even after water breakthrough.

This paper examines the heavy oil/water production control by ICDs and AICDs and discusses the flow loop test data (single and multiphase flow) to describe the performance of devices for various fluids under downhole conditions. Using an example model, the reasons for the superiority of AICD over ICDs is investigated under different scenarios. An optimisation workflow was used to optimise the well completion design i.e. the size and number of devices plus packer placements and numbers.

The results of several field applications of AICDs, from retrofitting the existing completions of the wells with very high water cuts (e.g. 98%) to brand new wells in heavy oil fields, will be discussed. AICD completion as a proactive-reactive device was found to be the most efficient completion at controlling the water production from high productive zones or the fractures, compared to the wells equipped with ICDs and other conventional completions while increasing oil production.

This paper provides insights about inflow control device applications in heavy oil wells and provides a comprehensive guideline on the selection of appropriate completions for the wells in these challenging reservoirs.
Integrated Approach for Evaluation of Free Gas Distribution Assists in Improved Well Management Practices in a Northern Kuwait Heavy Oil Field
Authors: Saikia Pabitra , Al-Rashdan Saad , Taqi Fatma , Al-Dohaiem Khalid , Al-Rabah Abdullah , Tyagi Aditya , Choudhary Pradeep , Ahmad Khalid , Kharghoria Arun , Malik Satinder , Zhang Ian , Cheers Mike
Published: December 2018

Free gas along with heavy oil production affects the progressive cavity pump (PCP) performance. This necessitates the strategy to perforate away from the free gas zone. To be able to do this, it requires an integrated approach to evaluate and map the spread of the free gas accumulation in the field. The paper shall present how this resulted in improved well performance with less free gas interference.

The methodology included the understanding of the production data, sub-surface geology and petrophysics; reservoir heterogeneity and free gas presence from wireline logs, core data and isotope analysis of gas collected during mud-logging and creation of maps and cross-sections showing both vertical and aerial spread of free gas accumulation. This was then integrated with existing production and well management practices, along with numerical simulation results. Such in-depth analysis helps to bring significant changes in well completion strategy and is a vital contribution to the WRFM strategy.

Unlike in conventional fields where depth is more and buoyancy pressures are large, gas can easily displace oil to accumulate in structural highs, in shallow heavy oil fields, free gas accumulation is a result of combination of structural and stratigraphic entrapment process. Vertical migration and lateral migration of gas is likely restricted by non-reservoir facies. As a result a consistent gas-oil contact (GOC) may not be present across large distances. Gas oil contact separates heavy oil by possible structural spill point and lithological boundary, dipping from south to north. Structurally higher areas are prone to localized gas accumulation. The completion stand-off from the gas base has a direct correlation with gas production. So the well management and production practice is to increase the stand-off from gas base to top perforations in future wells and to perform gas shut-off job in current wells to avoid free gas production.

The novelty of the current approach is that it will proactively help in completion strategy to reduce future free gas production, subsequent loss in natural reservoir energy and maintain the oil production target.
Workflows to Assist in Managing a Heavy Oil Field in the Middle Magdalena Basin, Colombia
Authors: Franco Francy , Useche Marcos , Vargas Leonel
Published: December 2018

Heavy oil production poses multiple challenges on oil companies such as intricate operations (complexity), high operational costs (efficiency control), and solutions for high viscosity and low API fluids (specific technology). This paper describes the technical workflows implemented in a heavy oil field located in the Middle Magdalena Valley basin in Colombia to assist in the complexity of an operation where cyclic steam injection is applied.

The complexity of producing heavy oil is due to its high viscosity at repository conditions, which limits the mobility of the fluid and the draining effect to a relative small area around the wellbore, thus it is required an infrastructure that involves many wells, flowlines, manifolds, and facilities to produce this type of crude oil. To support the surveillance and the technical decision-making processes in an operation with more than 300 wells, effective workflows were designed and implemented with the aims to eliminate mistaken decisions, optimize resources, and contribute to cost optimization.

The algorithms, foundation of these workflows, are presented with the analysis of different elements taken into consideration during the technical design process, such as well intervention program, field infrastructure, daily reports, and current well parameters. Additionally, four specific targets are discussed: Heat injection surveillance, which follows program plan vs current execution, including the calculation of heat values from operational conditions (pressure, steam quality, mass rate, and running time); Well test schedule, which organizes the wells test plan in a hierarchy considering flowline connections, well services plan, and priority well list (time since last test, wells with abnormal behavior); Dinalog plan, which is the foundation for artificial lift control; Steam injection scheme, which creates a suggested ranking of wells requiring steam stimulation based on current conditions (Wcut, WHT, production rate), time since last stimulation, and steam/oil ratio.

The developed workflows are applicable in both heavy oil fields, and light oil fields with a large number of wells, and they can be a valuable foundation for digital oil fields providing support for technical management and contributing to resolve the challenges of a vast operation.
Assessment of Waterflood Performance in a Heterogeneous Heavy Oil Field in Northern Kuwait
Authors: Kharghoria Arun , Garcia Jose Gregorio , AlRasheedi Khaled Saleh , Al-Rabah Abdullah Abdul , Sanwoolu Ayodele Olusegun , Husain Hisham
Published: December 2018

This study presents an assessment of heterogeneity on vertical and areal scales and discusses the development of methodology for a proposed waterflood scheme in a heavy oil field in Northern Kuwait. The field produces average 15° API crude of 50-100 cp at 100° F. The field has a complex geologic and stratigraphic architecture, and the associated reservoirs are highly heterogeneous in nature. Both numerical simulation and analytical models were used to assess the performance of the proposed waterflood.

Vertical and areal heterogeneity of the oil bearing formation were evaluated using Dykstra-Parsons coefficient, Lorenz coefficient and coefficient of variance methodologies. Both numerical simulation and analytical models were deployed to evaluate the waterflood performance under 5-spot and inverted 9-spot patterns for 20 and 10 acre spacing. An analytical excercise was carried out as a pre-check for the expected waterflood recovery factors.

Results from all three methods of heterogeneity assessment indicated the existence of a highly heterogeneous reservoir with average Dykstra-Parsons coefficients being greater than 0.8. A heterogeneity distribution map shows strong presence of areal heterogeneity. Ratio of the injectors to producers, pressure depletion schedule and associated recovery factors for planned pattern configurations were assessed from numerical simulation. Pattern by pattern heterogeneity indices were estimated and attempted to correlate to predicted flood performances.

This work highlights the impact of heterogeneity on the waterflood performance for a heavy oil reservoir to assess a more realistic production target, with integrated results from analytical and numerical methodologies.
Conceptual ESP Completion Design to Maximize Rig-Less Intervention and Reduce Overall Workover Rig Utilization
Authors: Al-Khaldy A. , BouKhamseen A. A. , Hassan J. M. , Hassan A. , Hantoush K. F. , Dashti R. , Al-Buloushi Z.
Published: December 2018

Well workover and completion operations presents multiple challenges due to the fact that operator have to plan ahead to select feasible completion equipment and tools in order to ensure that all the objectives are met from a well authority standpoint for expected production, future well interventions and expenditures during well lifecycle.

An ESP Y-Tool completion design is presented that uses a tail pipe to connect onto straddle packers creating a continuous path and permanent access for interventions below.

The novelty of this design is the ability to utilize straddle packers instead of spotting and squeezing cement for zonal isolation and still have access to conduct well interventions on zones below these straddle packers rig-less, optimizing workover rig utilization.

The ESP Y-Tool tail pipe has been modified to include a perforated pup joint with a centralized latch assembly, which connects to the straddle packer and eliminate the need of removing this assembly for future well interventions.