bluuebunny/crossref_metadata_2025 huggingface dataset:
SARA-Based Lumping Scheme: An Application Example
Authors: Altowilib Ali R. , Fraim Michael
Published: October 2019

Reservoir fluid properties play a crucial role in the upstream field development cycle. Petroleum engineers extensively utilize Pressure-Volume-Temperature (PVT) studies in applications such as calculations of pipelines’ pressure drop, and assessment of Enhanced Oil Recovery (EOR) strategies. These studies are generated from a series of lab experiments conducted on reservoir fluid samples in high pressure-high temperature (HPHT) lab environments, and commonly matched using Equation of State (EOS) software.

Feeding and characterizing the composition of a reservoir fluid in a PVT software play a central role towards understanding its behavior. These steps are heavily affected by the last carbon number measured and the lumping scheme used in the simulator. This paper investigates the application of splitting the plus fraction, and utilizing Saturates, Asphaltenes, Resins and Aromatics (SARA) analysis in enhancing viscosity prediction at atmospheric conditions.

In this study, three oil samples from fields with suspected flow assurance issues were selected. A fingerprint study was first conducted on all samples to ensure that they are representative of the original reservoir fluid, and free of any drilling fluid contaminants. The methodology used in this study is based on conducting compositional analysis and viscosity test on the selected samples. Furthermore, SARA analysis was conducted to enhance the characterization of reservoir fluid, and confirm asphaltene presence. Lastly, splitting technique and SARA-based lumping scheme were used to predict viscosity values at atmospheric pressure and were compared to experimental data.

The results of this work demonstrated the effectiveness of SARA-based lumping scheme on atmospheric viscosity prediction, which captured the plus fraction concentrated in the dead oil without compromising the computational time. Furthermore, the EOS software used studied the sensitivity of the simulation results to different compositions.
Development of an Integrated Wells - Pipeline Networks - Process Facilities Model for the Greater Burgan Oilfield from a Model Centric Approach
Authors: Desai Sameer Faisal , Al Jadi Issa , Al-Ghanim Wafaa , Al Sabea Salem H. , Al-Haddad Saud M. , Franco Francy Milena , Khor Siew Hiang , Bodwadkar Suhas V. , Saxena Aditya , Zhang Qiong Michael , Hapsari Hairuni Safri , Morales Fernando , Halabe Vijaya
Published: October 2019

Several efforts have been made in the past for generating an Integrated Asset Model (IAM) for the Greater Burgan field in Kuwait with mixed results on sustained utilization and benefits. A new effective full field Integrated Asset Model has now been developed within an Integrated Operational Excellence (IOX) program towards Digital Transformation of the Greater Burgan field.

A proven model centric approach has been adopted to bring multiple interdependent wells, pipelines networks, and process facilities models together into one single truly integrated asset model. The IAM platform also includes a water processing facility model which consists of 2 effluent water disposal plants, a crude oil export pipeline network and a water injection network model. Development of this integrated wells-network-facility-crude export-water processing facility-water injection network model incorporating the 14 gathering centers in the South and East Kuwait (SEK) asset focused on providing all the essential valuable inputs to business processes for better asset management, faster and more accurate decision-making and optimizing the hydrocarbon flow path all the way from the reservoir till the export point. The assessment was done at full field level where the complete system constraints, interactions and back pressure effects between more than 2000 different wells were fully accounted up to the crude processing facilities.

The availability of this fully integrated asset model with up-todate calibrated wells and network models and process models enables Kuwait Oil Company (KOC) engineers to better understand current well performance and production potential, identify any possible bottlenecks imposed by the large complex surface network and process facilities of Greater Burgan Oilfield. The simulated results such as pressure gradient, temperature gradient and erosional velocity ratio gradient across the production networks are presented on the GIS map for easy opportunity identification.

The paper describes how the Integrated Asset Modeler tool enables the asset teams to evaluate different operating scenarios to further enhance well performance and the overall asset productivity via re-routing well flow path to an appropriate header, identifying well workover opportunities, re-evaluating artificial lift design, adding new wells for field development and comprehensive understanding of well integrity and flow assurance studies. The integrated asset model can be coupled to the Greater Burgan reservoir model for comprehensive field development studies in future.
Disruptive Change to Correct Our Myopia in Enterprise Risk Management
Authors: Ali Al-Haidar , David Gurney , Craig Williams
Published: October 2019

Welcome to the future of ERM transforming from descriptive to analytic data for the risk register as the main objective because the risk register without statistical analysis equates to myopia, like a Heliographic Alphabet without the Rosetta Stone to translate. The scope of this paper is to demonstrate a statistical approach for the risk register where until now decisions have been made on descriptive data.

A proactive analysis is used in this paper to analyze the risk register data that will enhance our understanding of the risk register’s items to subsequently make better decision. The approach is to quantify the descriptive data in a statistical platform called SPSS (Statistical Package for Social Sciences). The quantified data is first tested using Coefficient Alpha analysis. Coefficient Alpha measures the reliability of the coded data, that is the accuracy level of the likelihood and impact items in the risk register. Coefficient Alpha is a matric that attempts to reflect our mindset or cognitive level during the risk assessment phase. Reliability is expressed as a number ranging between 0 and 1, where 0 indicating no reliability (much error) and 1 indicating perfect reliability (no error) (Peter 1979).

The result of Coefficient Alpha analysis is a composite score (%) to aid whether to progress to the next stage. The entire coded data is uploaded to the SPSS platform or Microsoft Excel to analyze the data for correlation and regression of the assessment items that affect the risk degree in the risk register. From observations related to the scale of likelihood with impacts levels, and the chosen items should be revised because their correlations will be in degradation mode after time. The new method is wider than the current approach, leading to better decisions about how to treat high and very high risks. In the new method the risks to be treated will be selected based on which items from the evaluation list are most affecting the risk degree.

The new method can form a comprehensive of risk management. This will enhance our understanding of the risk register in the petroleum industry, enhancing reporting, as well as removing some evaluation items that have no effect on the risk degree and adding alternative items in the risk register.
Challenges In Operating A Digital Oilfield - Lessons Learned From The Burgan Integrated Digital Field Pilot
Authors: Desai Sameer Faisal , Rane Nitin M. , Al-Shammari Baraa S. , Al-Sabea Salem H. , Al-Naqi Meqdad
Published: October 2019

Kuwait Oil Company initiatives for ushering in a new era of digital transformation of its assets to intelligently and optimally manage the Oil and Gas fields were successfully realized with the completion of three pilot projects entitled Kuwait Integrated Digital Fields (KwIDF). This paper discusses major achievements of the Digital Oilfield technology implemented in Burgan KwIDF project and provides an insight on the challenges in operating it.

The Burgan KwIDF pilot successfully transformed GC-1 production asset into a fully instrumented DOF comprising of digital instruments and infrastructure installed at well site and the production facility. Real-time production data is transmitted to a state of the art collaboration center that integrates data continuously with automated workflows for validation, modeling and tuning of well and facility models. Right time decision support information generated from smart visualization tools allow quick actions for production optimization, well and facility management in a collaborative work environment.

There is persistent value realization from KwIDF technology implemented in Burgan field. It has generated substantial cost savings with faster response time in restoring production and reduction in non-productive time. Driven by the digital environment asset production has sustained at target as production gain opportunities are capitalized and losses compensated quickly.

Over the period of time with experience in utilizing the DOF technology it has been observed that the technology sustainment is dependent on the technology providers to a large extent. The main components that require their continuous support are the digital instruments, proprietary software, hardware and related infrastructure. Technical expertise in each domain is necessary for ensuring continuous and smooth operations in the field, wellsite and collaboration centers. Development of an integrated team of domain experts is crucial for successfully managing the DOF operations. Change management initiatives for developing an in house user champion team is mandatory for ensuring sustainment. The important lessons learned and solutions are discussed in detail.
Practical Application on Mitigation of Formation Damage Induced by Gravel Pack Operations in Offshore Gas Condensate Field
Authors: Eldabbour Mohamed , Fadel Ayman , Soliman Ali , Safwat Hatem , Labib Amr , Belli Andrea , McLaughlin Ryan , Patey Ian T.M. , Munro Murdo S. , Jones David
Published: October 2019

Gravel pack completion operations are a sand production management technique that is considered successful if the well produces no sand and has minimal impact upon the potential productivity and hydrocarbon recovery. However, statistics show that many gravel packed wells suffer reduced productivity as a result of damaging mechanisms induced by gravel pack operations and completion fluids. This provides an opportunity for improved hydrocarbon recovery if the mechanisms are understood.

A study was conducted to simulate the alterations caused by the gravel pack operations including gravel carrier fluid, completion fluid and lost circulation material. Simulations using reservoir core samples were carried out at near-wellbore conditions, in order to examine operational fluid interactions with the reservoir and assess the impact of a stimulation fluid. Cores from a range of rock types were selected, and prepared to initial gas-leg saturation. An operational sequence consisting of completion fluid, gas production, stimulation fluid, completion fluid, and production of gas was carried out, with permeability measurements before and after the sequence.

In all core samples, the introduction of the completion fluid during gravel pack installation resulted in alterations of 30-60% reduction in core permeability. Geological interpretative analysis showed damage mechanisms including clay fines movement and pore blockage, dissolution of native cement, and retention of operational fluid in the pores. It was believed that retention of fluids was having the most significant impact upon permeability. Stimulations were carried out for all samples to quantify the effect of acid on removing the formation damage resulting from the gravel pack operations. The experiments showed 5-10% improvement on average except for one core sample, which showed 40% improvement.

Based upon the previous results, a modified sequence was examined, utilizing an alternative stimulation fluid/acid sequence and adding an extra operational stage. The experiments showed that after treatment an improvement of around 10% was noted, and after an additional stage, a further 8% improvement was seen. The final permeability was over 80-90% of the initial permeability, indicating that there was the potential for good productivity and recovery of hydrocarbons.

The results of the study were applied to seven gravel pack jobs in three wells and the field results showed the reduction in productivity after gravel pack installation was around only 10%, compared to previous wells which showed more than 50% reduction in productivity.
Optimization of Hydraulic Fracturing Design in Unconventional Formations: Impact of Treatment Parameters
Authors: Kolawole Oladoyin , Esmaeilpour Sajjad , Hunky Rabia , Saleh Laila , Ali-Alhaj Haiat K. , Marghani Mouna
Published: October 2019

Due to technical and economical limitations of hydrofracturing operations in unconventional reservoirs worldwide, an optimized hydraulic fracturing design is critical to achieve a successful well stimulation operation. The number and length of perforation clusters in each stage, proppant and fluid frac compatibilities, and optimum spacing, are some of the challenges inhibiting successful hydraulic fracturing operations across the world. In this study, we aim to investigate the effects of varying fracture-cluster lengths, proppant types and sizes, and frac fluid types, on hydraulic fracturing treatments using 2D and 3D simulation models. Our study relies on petrophysical log data, geologic data, well data, reservoir data, and production data from a well in the Eagle Ford shale formation. Firstly, we created stress log and developed a stress profile to determine fracture initiation location and orientation. We selected different combinations of frac-fluids and proppant types, 5 fracture-cluster lengths in a single stage, 2 different spacing lengths between fracture clusters, determined the maximum allowable treatment pressure, and selected an ideal fracture propagation model. Secondly, we selected an optimum treatment size, followed by performing the production forecast and the net present value analyses. In the third task, we determine the optimal specifications of the fracturing fluid and proppant, fluid volume and proppant weight, followed by creating a schedule for fluid injection and proppant mixing, and injection pressure profile prediction. Our results show that greater cluster lengths provide better and optimized hydraulic fracture treatment in some cases because of greater proppant coverage, fracture conductivity, stimulated reservoir volume (SRV), fracture half-length, and propped length. In the results obtained from varying proppant sizes and frac fluids in cases 2 and 3, we observed that Northern White 30-50 proppant produced a lower fracture conductivity (average of 2.0 md-ft) and fracture half-length (91 to 123 ft), in comparison with proppant composed of Badger 100 mesh and RC Sand PC 16-30, which achieved a greater fracture conductivity (> 3.0 md-ft) and fracture half-length (129 to 148 ft). In the 3 cases we investigated, we observed that stress shadowing and interference hindered the growing fractures which eventually led to a collapse of some fractures. We believe that our preliminary study will provide valuable critical decision-making during hydraulic fracturing operations in various unconventional formations across the world.
Potential of Copper-Based Oil Soluble Catalyst for Improving Efficiency of In-Situ Combustion Process: Catalytic Combustion, Catalytic In-Situ Oil Upgrading, and Increased Oil Recovery
Authors: Yuan Chengdong , Mehrabi-Kalajahi Seyed Saeed , Sadikov Kamil , Varfolomeev Mikhail A. , Emelianov Dmitrii A. , Rodionov Nikolay O. , Amerkhanov Marat I.
Published: October 2019

In-situ combustion (ISC) is a promising thermal enhanced oil recovery (EOR) method for heavy oils. However, its field application is still limited due to difficulty in ignition, low combustion efficiency, unstable combustion front, etc. To improve the success rate of ISC process, we investigated the effectiveness of copper-based oil soluble catalyst for catalyzing combustion and in-situ upgrading of heavy oils.

High-pressure differential scanning calorimetry (HP-DSC) and TGA were used to investigate the effect of catalyst on the thermochemistry (onset temperature, temperature range of reaction interval, heat effect, etc.) and kinetic parameters of combustion process. A Porous medium thermo-effect cell (PMTEC) was designed to study the catalytic combustion of heavy oil in porous media under air flow. And, a visual combustion tube (VCT) was developed to study the catalytic effect of catalyst on the ISC process, including improving combustion front propagation, in-situ upgrading of heavy oils, and oil recovery.

HP-DSC results showed that copper-based oil soluble catalyst significantly shifted the low-temperature oxidation (LTO), transition stage (FD), and high-temperature oxidation (HTO) into lower temperature ranges. Especially for HTO, the end temperature was decreased about 120 °C. It was finished at a narrower temperature region with a higher heat flow, which implies that the combustion efficiency of HTO was greatly improved. TG-DTG data also showed the combustion reaction was transferred into lower temperatures. In addition, from TG-DTG and kinetic data, it can be concluded that the catalyst significantly reduced the activation energy in FD and HTO stage, which thus decreases the reaction barriers between FD and HTO and increases the continuity of reactions between FD and HTO.

PEMTC experiments also showed that the ignition temperature of heavy oil combustion in porous media in airflow was decreased about 46 °C by copper-based catalyst. VCT experiments indicated that in the presence of copper-based oil soluble catalyst, combustion front propagate faster, oil recovery was 10% higher than without catalyst, and a deep in-situ oil upgrading was achieved with a significant viscosity reduction (9 times lower) and increase of saturates content (especially alkanes with lower carbon number C11-C17). All these results showed that copper-based oil soluble catalyst has a great potential in improving the efficiency of ISC process and in-situ oil upgrading. Its application can help to improve the success rate and wide application of ISC process for heavy oil recovery, which will promote the highly efficient development of heavy oil resources.
Visual Analysis of SAGD with Chemical Additives
Authors: Huang Jingjing , Babadagli Tayfun
Published: October 2019

SAGD (steam assisted gravity drainage) has been proven as an effective technology to enhance heavy oil/bitumen recovery. The main shortcoming of this method is its inefficiency, a result of high water and energy consumption. As a solution to SAGD efficiency improvement, we propose the addition of chemicals resulting in higher recovery and reduced steam consumption. The objective of this paper is to screen new generation chemicals as additives and study the mechanisms and optimum injection strategies. This screening was achieved through Hele-Shaw type macroscopic visual experiments.

We previously screened a wide variety of chemical additives (Bruns and Babadagli 2017, 2018) for steam flooding. As a continuation of this work, these chemicals were tested for SAGD conditions using a new visual experimental design where the optimal injection strategies were identified, eventually providing a reference for the selection of chemical additives for field applications.

11 conventional and new generation chemical additives (heptane, biodiesel, DME, LTS-18, Tween 80, Span 80, Novelfroth 190, ionic liquid (BMMMIM BF4), silicon dioxide nanoparticle, DES9, and DES11) were selected based on both their strong thermal stability and enhanced oil recovery capability. The recovery improvement mechanisms for the different chemical additives and different injection strategies were identified through flow characteristics, emulsifying ability, viscosity reduction capability, and wettability alteration. Simultaneously, the mechanisms were studied from a macro perspective via analyzing areal sweep efficiency and microscopic oil displacement efficiency together with observing the images acquired during the process.

Three different injection strategies were applied for each chemical: (1) chemicals were injected at the beginning, (2) in the middle, and (3) at the end of the steam injection. The chemical additives played different roles in recovery improvement, and different chemical addition strategies yielded different mechanisms. Heptane exhibited extraordinary characteristics with maximum "steam saving" (34.52%) when the middle injection strategy was applied and maximum ultimate oil recovery (64.75%) was obtained for the end injection strategy due to the ability to reduce the viscosity of heavy oil by dissolving around the chamber edge. Steamflooding with Novelfroth 190 showed an excellent performance for the middle and end injection strategies due to its ability to develop rapid oil drainage "channels". The addition of surfactant LST-18 presented the ability to improve the EOR by forming emulsions. Additionally, the distributions of the steam chamber in the Hele-Shaw cell were different due to the changed flow characteristics when the same chemical additive was injected at different times, thus showing the ability to reduce viscosity and form emulsions with different strengths.
Management of Barium Sulfate Precipitation in Rich Iron and High pH Environment during Stimulation Operation
Authors: AlAamri Jamal , AlDahlan Mohammad
Published: October 2019

The quality of base fluid used in the preparation of different stimulation and wellbore cleaner recipes is very critical toward high efficient job. However, due to the limited access to adequate quality water sources, efforts to minimize the operational impacts of such less quality source is grown rapidly. High sulfate mixing water is well known example of such low quality water and which results in sulfates deposits during stimulation operation. In this paper, an effective management of barium sulfate precipitation in high pH and iron rich environment is presented.

A simulated low quality water with high sulfate content of more than 500 ppm and produced water of high barium and iron contents were proposed and prepared for this study. Static jar compatibility tests at high pressure and temperature were conducted at different ratios to study the potential precipitation of sulfates and iron deposits. Precipitated solids were identified by Scanning Electron Microscope (SEM) and aqueous phases were analyzed by ICP-OES and IC for barium, iron and sulfate content. Then, three different scale inhibitors (SI) were assessed at different loadings for their efficiency to prevent scaling. Chelating agent was also used to enhance the efficiency of scale prevention and work to chelate iron ions presented in the produced water. The effect of high pH in the precipitation quantity was also studied.

Results showed high potential of barium sulfate precipitation at different maxing ratios. At higher ratios of produced water, the presence of more iron deposit was observed. Analysis confirmed the barium sulfate deposition during the static jar tests. Scale inhibitors performance were found to be functions of loading and the presence of iron. Chelating agent improve the performance of SI and led to minimum precipitation potential.

An optimized fracturing recipe was designed utilizing the high sulfate source water and proved to minimize the impact of sulfates scaling. The use of the chelating agent was found to be critical to enhance the scale inhibitor tolerance toward iron presence.
Impact of Rate History on Analysis of Diagenetic Fracture Injection Test DFIT and Other Impulse like Tests
Authors: Motealleh Siyavash , Jones Jack , Ghanbarzadeh Soheil
Published: October 2019

This work is motivated from issues that arise during the analysis of dynamic fracture injection tests (DFITs). It often occurs with DFITs that the rate history before shut in is somewhat uncertain, but the total injection volume is measured accurately. The analysis method (PTA) commonly used by the reservoir engineering community is always assumed to require an accurate and detailed rate history. In this paper two main questions are addressed: What is the impact of both poor rate measurement and imprecise knowledge of the times rates change on the shape of the resulting log-log diagnostic plot and subsequent interpretation/analysis?If the rate history is defined in any way that is consistent with total volume injected, is that sufficient to perform some useful analysis of the data?

In this study, we design a DFIT for a well and reservoir with known properties, then we use analytical and numerical simulation to produce pressure responses for the test (during injection and fall off). In the next steps, we analyze the pressure and derivative response under the conditions below: Right rate history and total volume injected.Wrong rate history, but right total volume injected.Wrong rate history and total volume injected.

The method above was repeated for a vertical well with a hydraulic fracture and a vertical well with no fracture, in order to confirm similar observation for a more standard well test when compared to a DFIT.

The results presented here imply that if the imposed rate history is incorrect with respect to rate values or times when the rate changes occur then the early time response shape is distorted in comparison to the case where the rate history is defined correctly (e.g. in a DFIT wellbore storage and linear flow before closure do not reflect the correct derivative shapes). However, if the rate history is defined in any way that reproduces the correct total volume injected, then the late time radial flow period remains unaffected and, hence, the ability to estimate reservoir properties (e.g. transmissibility and reservoir pressure) from the test is preserved. Thus, it appears that the late time part of the response is controlled by total volume injected and that total volume injected is sufficient information for estimation of reservoir properties for radial flow. This agrees with/confirms the common analysis approach used by the completions community based on the instantaneous line source solution presented by Gu, et.al. (1993)
Selecting Artificial Lift or Deliquification Measures for Deep Gas Wells in The Sultanate of Oman
Authors: Veeken Cornelis , Al Kharusi Dawood
Published: October 2019

Most of the gas wells operated by PDO in the Sultanate of Oman suffer from liquid loading during their production life cycle. Artificial lift or deliquification measures are key to mitigate liquid loading to maximize the capacity and ultimate recovery of these gas wells. A wide range of deliquification measures exist of which the performance depends on individual reservoir, well and surface parameters. This paper describes the use of an integrated production and economic forecasting tool that compares the technical and economic performance of different (combinations of) deliquification measures to select future deliquification scenarios.
Role of Geochemistry and Real-Time Advanced Gas Interpretation in Development Strategies of Depleted Reservoirs
Authors: El Gezeery Taher Mohamed , Halawa Youssef Ahmed , AL Shemali Nasser , Al Rashidi Mohamed , Matar Saad , Ismael Aziz , Silambuchlvan Jeevan , Al-Rashidi Tahani
Published: October 2019

The Minagish Oolite is one of the main reservoirs in the Minagish Field, Southwest Kuwait. The field is a large 4-way dip closure anticline structure, covering an area of about 90 square kilometers and with around 900feet of carbonates of the Minagish formation. The Middle Minagish member is the main reservoir, consisting of oolitic limestone with high permeability in the range of 10 to 1000 mD. The Lower Minagish member contains dense fine grained wackestones to packstones with low permeability. The Middle Minagish and Lower Minagish oil reservoirs contain highly undersaturated oil with API gravities of 28-34 °API and share a common FWL at 9950feet TVDSS.

The dynamic model built along with time lapsed historical (production/injection) and well surveillance (PLT, TDT, well test) data are used for tracking the movement of injected water and gas, monitoring fluid contacts and changes in saturation with time, optimizing production and planning of new wells. Nonetheless, due high density of producers existing around the field causes mutual interference amongst the neighboring wells and surprises arise while drilling new wells.

Real-time Geochemical analysis on elemental and mineral concentrations within drill cuttings/core chips, integrated with advanced mud gas data, can provide an additional analytical dataset to assess reservoir depletion and water encroachment. This advanced surface logging technology can give a better indication on water bearing zones and water encroachment when MWD/WL logs have resolution issues. When geochemical and mud gas proxies are integrated with other data sets (viz. logs, and dynamic data), they provide a better control on lithological changes and water bearing zones, throughout the entire reservoir.

Integrated geochemical and advance mud gas analysis in depleted Minagish reservoir has helped to confirm zones of interest and to determine leading edge of water aquifer. Ultimately this enabled for a unique completion design. The well MN-X, object of the study, represents a valuable case where it has been possible to identify water encroachment through geochemical proxies, aiding the completion strategy.
World's Largest Yard Testing of a Thixotropic Polymer Sealant for Chemical Annular Plug Applications in Low-temperature Horizontal Wellbores
Authors: Matar Khaled , Santin Yoann , Taku Khan , Koldig Jesper
Published: October 2019

Forming a retrofit annular plug on controlled acid jet (CAJ) liners in horizontal wells can be challenging. Several conformance technologies have been tested with mixed results; optimal chemical placement is problematic, and results show that conventional treatments either slump or float along horizontal sections, fail to withstand the desired differential pressure, or are not achievable at low temperatures.

This paper describes laboratory improvements and a large-scale yard test of a thixotropic polymer sealant (TPS). The TPS system is composed of an organically crosslinked polymer combined with optimized rheological modifiers, which enable predictable and controllable crosslinking times. This allows precise TPS placement into the horizontal or deviated wellbores to help control unwanted water or gas.

Extensive laboratory testing was conducted on the TPS system to formulate the optimal rheology at low temperatures. A specialized laboratory-scaled test cell was purposely built to verify the development of the thixotropic blend at low temperatures of 35 to 40°C.

After successful laboratory testing, a 520-ft long yard test was conducted to mimic a field trial. It consisted of centralized 4 1/2-in. tubing run horizontally inside a 7-in. casing. Four predrilled holes of 4-mm diameter were located midway along the tubing to represent the perforations, providing communication to the annulus of the tubing and casing. A 2.25-in. outer diameter (OD) high-pressure hose, representing coiled tubing, was placed inside the 4 1/2-in. tubing and used to deliver the TPS fluid to the perforations. The entire setup was pressure-tested to 5,000 psi and heated to 40°C using an insulated heating blanket. A high-pressure pump was used to pump and displace 6 bbl of TPS, which was sufficient to form a 300-ft annular plug. The chemical was allowed to crosslink and set for 45 hours.

Results of this yard test showed that a 300-ft TPS annular plug is capable of withstanding up to 4,620-psi differential pressure. The setup was then cut at various locations, both treated and untreated, to confirm, assess, and observe TPS placement in the cross-section of the tubulars. It was observed that the TPS can flow in the smaller spaces between the tubing and the centralizer, helping ensure optimal sealing.

The TPS system described here can be used to help reduce unwanted water or gas production in long horizontal wells with CAJ liners. The open annulus between the preperforated liner and the formation makes selective isolation for the presence of thief zones, high-permeability zones, or fractures extremely challenging. Left untreated, this can eventually result in a large increase in water production and eventually a reduction in the economic life of the field.
Study on Oppositely Charged Polymer and Surfactant Mixture for Enhancing Oil Production
Authors: Xu Limin , Han Ming , Zhang Xuan , Fuseni Alhasan
Published: October 2019

Polymer-surfactant mixtures in aqueous solutions present unique rheological and interfacial properties that promote their applications in chemical flooding. The objective of this study is to investigate the interaction between anionic polyacrylamides and cationic surfactants in different temperature and salinity conditions and the potential application of the polymer-surfactant mixtures in carbonate reservoirs. Cationic surfactants were selected owing to low adsorption on carbonate rocks. Compatibility tests of polymer-surfactant mixtures were conducted in brine with different salinities to study the interaction between anionic polymers and cationic surfactants in the presence of salts. The effect of cationic surfactants on polymer viscosity at different temperatures was investigated.

The compatibility of the mixtures of the cationic surfactants and the anionic polymers was significantly improved in high salinity injection water (with a total dissolved solid of 57,670 mg/L), compared with the compatibility in deionized water. This is attributed to the shielding of polymer and surfactant charges by the salts, which diminishes the electrostatic interaction between the chemicals. Rheological measurements indicated that the polymer viscosity increased in the presence of the cationic surfactant CAS-S or CAS-B. This effect was decreased at 90˚C. Other cationic surfactant CAS-1 or CAS-3 slightly increased the polymer viscosity at 25˚C and significantly decreased the viscosity at 90˚C. These observations can be explained based on the surfactants self-assembly. At room temperature, CAS-1 and CAS-3 form spherical micelles while CAS-S and CAS-B form wormlike micelles. The entanglement of the polymers with wormlike micelles explains the observed viscosity enhancement. At 90˚C, wormlike micelles became shorter which weakens this viscosity enhancement effect. In conclusion, the charges and self-assembly structures of surfactants play an important role in the performance of polymer-surfactant mixtures that should be taken into account in the design of optimal formulations. This work provides the insight of interaction between anionic polymers and cationic surfactants with different self-assembly structures for the potential application in improving oil production.
The Animated Reservoir Plumbing: A Time-Lapse Integrated Reservoir Description Schematic
Authors: Hadidi Shahab , Wahaibi Ahmed , Sabahi Mohammed , Aghbari Hilal , Saaidi Abdulhamid , Suwannathatsa Sakharin , Mahajan Sandeep , Miotto Alberto
Published: October 2019

The reservoir plumbing is a conceptual integrated reservoir description diagram that combines the reservoir architecture, fluid fill and fluid dynamics. The objective of the reservoir plumbing is to highlight the main features in the reservoir that might influence oil and water movements and possible subsurface realizations. The resultant schematic(s) will aid in identifying main uncertainties impacting hydrocarbon development, revealing reservoir data gaps, flagging any bypassed oil and assisting in the revision of the current development or any additional development opportunity. The animated reservoir plumbing is taking the concept to a new level where the reservoir history is presented in sequential events starting from the deposition setting prior initial charge and up to the current state.

The inputs into each time step of the reservoir plumbing are the initial reservoir properties and development activities that had an influence on hydrocarbon and water movements. The required properties are listed with the source of information (seismic data, core, logs, pressure data, PVT, etc) including the degree of uncertainty and their impact on hydrocarbon recovery.

Based on the gathered information, interpretations are translated into conceptual diagrams and presented in snapshots which include;

the initial depositional setting before initial hydrocarbon charge, hydrocarbon migration, any structural or diagenetic changes occurring after hydrocarbon charge that might influence fluid fill or movement, any additional hydrocarbon migration events and subsequent structural changes - if any - and, possible fluid movement paths (both oil and water) resulting from development wells.

Different versions of the reservoir plumbing might be required to represent alternative subsurface realizations.

The animated reservoir plumbing was created for a carbonate field of the Lower Shuaiba and Kharaib Formations in the Sultanate of Oman at the beginning of the Field Development Plan update. It was used to decide the modelling approach, identify improvements in the development strategy, recognise potentially bypassed oil and acquire additional data ahead of modelling to prove the concept of this bypassed oil.
Uncertainty Assessment of Hydrocarbon in Place With Geological Models Satisfying Gravity-Capillary Equilibrium
Authors: Guérillot Dominique , Bruyelle Jérémie
Published: October 2019

In a reservoir, gravity forces lead fluids to stratify according to their density, and transitions zones appear around contacts (water-oil and gas-oil contacts). These transitions zones are gradual variations of saturation of each phase. These saturations are often generated using geostatistical methods leading to errors in the calculations of fluid in place. They must be calculated in a physical manner using capillary pressure curves associated with lithofacies. In this paper, a physical volumetric method to calculate the hydrocarbon in place with a high-resolution geological model is used on data coming from a synthetic field: the Brugge field. The uncertainties on hydrocarbons in place are evaluated using the Monte-Carlo method.
Impact of Fines Type on Gas Flow Using 3D Micro-Computed Tomography
Authors: Al-Raoush Riyadh , Hannun Jamal , Jarrar Zaher , Alshibli Khalid , Jung Jongwon
Published: October 2019

Methane hydrates are promising unconventional energy source with natural reserves above 1,000 Trillion m3. Hydrates are found in saturated sandy sediments, where multi-phase flow of gas takes place through sediment's pores, physical phenomenon at pore-scale controls flow properties. Gas permeability is highly affected by fines type due to migration, clogging and bridging reducing gas flow. Fines migration has huge influence on storage and recovery of oil and gas resources from the subsurface. There is a knowledge gap of fines effects on gas production from sandy sediments, especially at pore-scale, in homogenous porous media. Therefore, there is a need to model and quantify fines impact on multi-phase flow using 3D reconstruction to better understand gas recovery systems.

The pores in which gas flow through are reconstructed using 3D synchrotron X-ray micro- computed tomography images of sand sediments, at resolution of 3.89 micron per voxel. Sand was mixed with fines and deposited in test columns. Kaolinite and Montmorillonite clay fine particles were added in different columns, each system was scanned at four stages with varied saturations of brine as CO2 gas was injected in real time while scanning. Images were processed for 3D visualization, segmentation and quantification for each system. Effects of swelling and non-swelling clays were characterized to understand multi-phase flow of gas at pore-scale.

Findings revealed that fines accumulate at sand-brine and brine-gas interfaces. As fines concentration increased, gas percolation decreased. Further increase in fines concentrations resulted in blocking local gas flow causing pressure variations enough to create fractures that allows gas to escape and percolation to rise. In unconsolidated media, the pore space geometry will change due to sand grains movements. At high concentrations, different fines types produce altered gas flow regimes, Kaolinite which is non-swelling clay resulted in fractures while montmorillonite which is swelling resulted in detached gas ganglia entrapping the gas. Generally, increasing fines reduces gas percolation and further injection of gas reduced permeability. The finds herein are critical in understanding the impact of fines migration during gas flow in sand, they can be applied to characterizing and predicting two phase properties of unconsolidated sediments.

The qualitative and quantitative findings achieved in this work in 3D, agree with other observations in recent literature on 2D micromodels. Understanding the fluid physics in homogenous sand systems is an essential step to quantify fines impact on heterogeneous rock systems. The work helps in improving flow characterizing at pore scale, to mitigate to formation damage problem and advance reservoirs upscaling capabilities.
Development of an Integrated Approach to Improve Heavy Oil Recovery From a Low-Permeability Carbonate Reservoir
Authors: Al-Murayri Mohammed Taha , Kamal Dawood S. , Al-Tameemi Naser , Li Zhitao , Delshad Mojdeh
Published: October 2019

Umm Gudair/Abduliyah Tayarat reservoir is a challenging EOR target because of its high oil viscosity, low permeability, and carbonate mineralogy. A previous feasibility study indicated that a hybrid EOR thermal and chemical method combined with IOR techniques could produce significant amount of oil from this reservoir. The objective of this study was to identify the most viable reservoir-specific EOR/IOR approach taking into account techno-economic considerations.

With the latest well logging data, production history, and petrophysical measurements, the Tayarat reservoir simulation model was revisited. Consequently, this simulation model was updated and calibrated to reflect field and lab observations. In addition, lab tests that demonstrated good transport and oil recovery performances of a selected polymer in low permeability reservoir cores were modeled to provide parameters for field-scale scoping simulations. Sensitivity studies were conducted to evaluate the effects of injection temperature, viscous fingering, well configuration, etc. A simple economic analysis was conducted to demonstrate the economic benefits of the proposed hybrid EOR/IOR method.

Calibrated by history matching the actual production data, the Tayarat reservoir model included a barrier zone that would prevent influx from a bottom aquifer. A better match was obtained by assuming that the reservoir is strongly water wet, which is consistent with the latest laboratory imbibition and contact angle measurements. Reservoir transmissibility was increased to represent possible fractures/microfractures in the carbonate reservoir. Scoping simulations based on a selected sweet spot of the Tayarat reservoir showed that primary recovery was ineffective due to the lack of a bottom aquifer, and waterflood recovered significantly more oil. A hybrid thermal/chemical EOR process was more effective when a preflush of hot water was considered to heat up a portion of the reservoir ahead of chemical injection. When viscous fingering was neglected, oil recovery could be erroneously as high as 50% more compared to the case when viscous fingering was modeled. Simulation results showed that about 19% of OOIP could be recovered using the hot waterflood followed by hot polymer flood, i.e. about 130% higher than conventional waterflood corresponding to a water cut of 95%. The chemical cost for incremental oil produced with our most promising approach was $10/bbl of incremental oil.

This integrated laboratory and simulation study should provide meaningful insights into tackling challenging low permeability and/or heavy oil carbonate reservoir using novel chemical EOR techniques.
Tight Carbonate Reservoir Characterization and Complition Optimization Using Magnetic Resonance in Horizontal Well, Umm-Gudair Field, West Kuwait
Authors: FawzyFahmy Mahmoud , SinghaRay Dipak , Zekraoui Mohamed , Ghioca Monica , Qutainah Riyad
Published: October 2019

Middle Marrat resrervoir of Jurrasic age is a tight carbonate reservoir with vertical and horizontal heterogeneous properities. The well placement over deep elonogted anticline with steep dips, geosteering and lowering of production liner are challenging, therefore the field is being developed using horizontal wells cutting across multiple reservoir layers to maximize reservoir contact and driange

The low clay content in Marrat reservoirs gives low gamma ray counts, which makes the identification of reservoir layers identification difficult. In addition, the high-resistivity responses from hydrocarbon-bearing pay-zones and from the tight layers make the identification of the reservoir sweet spots difficult as well. Slim-hole magnetic resonance (NMR) logging was deployed in wash-down mode for identifying reservoir sweet-spots as a lithology-independent porosity and formation fluid characterization tool.

Magnetic resonance was acquired with dual wait time enabled T2 polarization to differentiate between moveable water and hydrocarbons. After acquisition, the standard deliverables were porosity, the effective porosity ratio, and the permeability index to evaluate the rock qualities. Porosity was divided into clay-bound water (CBW), bulk-volume irreducible (BVI) and bulk-volume moveable (BVM). Rock quality was interpreted and classified based on efftective porosity and permeability index ratios. The ratio where a steeper gradient was interpreted as high flow zones, a gentle gradient as low flow zones, and a flat gradient was considered as tight baffle zones.

Based on the MR flow units and fluid types (CBW, BVI and BVM), the drilled interval was classified into six compartments of high flow, one compartment of low flow, and five tight baffle zones. Accordingly, the perforation plan was optimized to fit the high flow units only. Comparing to the conventional log analysis, NMR excluded approximately 1000 ft of non-productive reservoirs, leading to a significant cost savings (250,000 USD) in perforationand production optimization.

The well was drilled with a distance-to-bed boundary tool; however, enormous potential exists to use this slim MR tool as a non-radioactive sourceless solution for geosteering through reservoir sweet spots while delivering wells that are more productive safely.