bluuebunny/crossref_metadata_2025 huggingface dataset:
Impact of Viscous Instabilities on WAG Displacement
Authors: Skauge Arne , Skauge Tormod , Sorbie Kenneth Stuart , Bourgeois Marcel Justin , Chang Paulo Lee Kung Caetano
Published: October 2022

In earlier studies, we have investigated water-oil displacement at adverse mobility ratios, and the impact polymer may have to improve the oil recovery. This paper addresses gas-oil displacement which is inherently an unstable displacement process, due to the low phase viscosity and density of the gas phase. In this work, a systematic study of viscous fingering for gas injection and WAG is performed as a function of rock heterogeneity, viscosity ratio, and density difference. The results of these studies aim to improve the design of gas injection and WAG to optimize sweep and total oil recovery with least possible amount of gas recycling.

The numerical modelling has been carried out using commercial reservoir simulators. The methodology for describing viscous fingering is similar to that presented by Sorbie et al. (2020), where a 4-stage approach was proposed; viz. (i) choosing the form of the fractional flow curve, (ii) from fractional flow deriving a set of relative permeability curves which gives the maximum total mobility function, (iii) establishing an appropriate random correlated permeability field and (iv) simulating the process with a sufficiently fine grid.

Simulations have been performed with fine grid 2D, using variations in viscosity ratio and phase densities. The impact of heterogeneity has been studied by varying the local distribution of rock permeabilities.

Here we use experimental data from different sources to determine WAG parameters. Horizontal gas injection gives viscous fingers, and the unstable flow leads to very early gas breakthrough. We studied the influence of gravity on formation and development of viscous fingers. By combining experimental data with simulations, we show that viscous instability of the gas-liquid front can be captured in simulation models based on relative permeabilities gained from gravity stable core floods.

Numerical simulation studies confirm the recommendations and show the benefit of altering the core positioning. The simulation of generic core flow experiments was performed by using mm scale grid cells and heterogeneous permeability fields with rather short correlation lengths.

In immiscible gas displacement, the finger pattern appears to be mostly dominated by the viscosity ratio. However, these observations will mainly apply in the viscous limit when the other forces, capillarity and gravity, are small. Trapped gas during WAG injection is found to dampen the gas fingers, even in a 2D cross-sectional case. In a full 3-D case the extent of the three-phase zone adds to the differences between the WAG and gas injection cases.

Simulation studies show examples where stabilized flow relative permeability can model unstable displacement in fine grid models. The unstable horizontal oriented flow gives early gas breakthrough and viscous fingers dominate the flow. Shorter WAG cycles seem to be beneficial to optimize oil recovery and reduce gas recycling.
Synergies of Alkali and Polymers - Decreasing Polymer Costs and Increasing Efficiency
Authors: Hincapie Rafael E. , Borovina Ante , Clemens Torsten , Hoffmann Eugen , Tahir Muhammad , Nurmi Leena , Foedisch Hendrik , Hanski Sirkku , Wegner Jonas , Janczak Alyssia
Published: October 2022

Alkali injection leads to in-situ soap generation of high TAN number oil and residual oil reduction accordingly. We are showing that the performance of AP floods can be optimized by making use of lower polymer viscosities during injection but increasing polymer viscosities in the reservoir owing to "aging" of the polymers at high pH. Furthermore, AP conditions enable reducing polymer retention in the reservoir decreasing the Utility Factors (kg polymers injected / incremental bbl. produced).

Phase behavior tests were performed to understand the oil/alkali solution interaction and interfacial tension (IFT) was measured. Micromodel floods addressed displacement effects while two-phase core floods covered the displacement efficiency of alkali polymer solutions. We used aged polymer solutions to mimic the conditions deep in the reservoir and compared the displacement efficiencies and the polymer adsorption of non-aged and aged polymer solutions.

IFT measurements showed that saponification (41 μmol_g saponifiable acids) at the oil-alkali solution interface is very effectively reducing the IFT. Alkali phase experiments confirmed that emulsions are formed initially and supported the potential for residual oil mobilization. Aging experiments revealed that the polymer hydrolysis rate is substantially increased at high pH compared to polymer hydrolysis at neutral pH resulting in 60 % viscosity increase in AP conditions. Within the reservoir, the fast aging of polymer solutions in high pH results in increase to target viscosity while maintaining low adsorption owing to alkali and softened water. Hence, injectivity of alkali polymer solutions can be improved over conventional polymer flooding. The two-phase experiments confirmed that lower concentration polymer solutions aged in alkali show the same displacement efficiency as non-aged polymers with higher concentrations. Hence, significant cost savings can be realized capitalizing on the fast aging in the reservoir. Due to the low polymer retention in AP floods, less polymers are consumed than in conventional polymer floods significantly decreasing the Utility Factor (injected polymers kg/incremental bbl. produced).

Overall, the work shows that Alkali/Polymer (AP) injection leads to substantial incremental oil production of reactive oils. A workflow is presented to optimize AP projects including near-wellbore and reservoir effects. AP flood displacement efficiency must be evaluated incorporating aging of polymer solutions. Significant cost savings and increasing efficiency can be realized in AP floods by incorporating aging of polymers and taking the reduced polymer adsorption into account.
Intelligent Deepwater Advanced Solutions Hub for Value Maximization Throughout Asset Lifecycle
Authors: Ryu Sam , Chaney Carmela , Xu Wei , Hill Amanda , Zeng Yifei , Guha Amitava , Sun Wei , Garza-Rios Luis , Firmian Michael , Huang Xiaojun , Smith Benjamin , Ford Steven
Published: October 2022

The challenges with life-cycle management of an offshore asset, coupled with multi-discipline system engineering, and multiple competing project objectives provide an opportunity to seek a disruptive approach for maximizing value. The objective of this paper is to introduce ExxonMobil's new approach called intelligent Deepwater Advanced Solutions Hub (iDASH) where various engineering tools are strategically integrated to maximize value and improve decision quality utilizing advantages of latest digital technologies.

Establishing a cloud-based centralized hub with engineering tools that can generate holistic solutions is a novel and disruptive approach given the unique and complex nature of large-scale development and management of deepwater resources. As the energy industry goes through a challenging situation where more complex and competing objectives exist, the proposed iDASH can provide a new and unique approach to move in the right direction by leveraging integrated tools and data-driven technologies.

Offshore developments require a wide range of expertise areas including reservoir, wells, flow assurance, subsea, flowlines, risers, topsides, marine, geotechnical, costing, and project economics. Key challenges to asset life-cycle management include uncertainty from subsurface, limited number of alternative concepts, slow evaluation turn-around time, inability to integrate processes across multiple disciplines, and non-streamlined data transfer among different stages of a project. The iDASH approach proposes solutions by emphasizing the integration of tools, continuity among different stages of a project, and cross-discipline connectivity. Logically following typical project stages, iConcept, iDesign, iOperate, and iDecom are addressed as four pillars of iDASH to ensure value maximization.

Locating and integrating various engineering tools in a cloud-based centralized hub allows for cross-discipline collaboration, optimization, and faster cycles with either better solutions or multiple alternative options. Progress in this space can decrease capital expenditure (CAPEX) or increase net present value (NPV), resulting in faster monetization of an asset or a shorten payback time. Specific use cases and proofs of concept with different engineering tools demonstrate the feasibility of iDASH and value maximization. Specifically, a trade-space analysis for improving decision quality seeking an optimal concept is demonstrated as an iConcept tool. A riser optimization case is demonstrated as an iDesign tool. A mooring integrity checker is illustrated as an iOperate tool. Results validate that challenges in asset life-cycle management can be overcome and that the proposed disruptive approach offers quick, logical, strategic, and insightful means for managing the value maximization of an asset.
Innovative Upscaling First HT/HS Polymer Injectivity Tests Towards Multi-Well Pilots
Authors: Mahboobah Dyala Amin , Romero Carolina , Kaduluri Viresh , Ali Sawsan , Pimenta Gervasio , Al Saadi Haitham Ali , Luqman Abdulla , Altamimi Maitha Abdul Rahman , Huynh Francois , Gathier Flavien , Dupuis Guillaume , Garnier Olivier Francois
Published: October 2022

Following the successful results of the two Polymer Injectivity Tests (PIT) carried out within ADNOC Onshore fields, this paper focuses on the surface de-risking plan for the multi-well pilot's preparation. The objective is to ensure that the designed Key Performance Indicators can be met by the upscaled process design related to polymer solution quality, viscosity, concentration, injection rate and skid running time. The main challenges and lessons learnt from the two PIT operations were implemented in the polymer skid upgrade and helped define the polymer solution and equipment qualification criteria to meet the requirements set for the final skid's design and operation. This work is part of a larger de-risking strategy developed from laboratory studies to polymer field deployment, in preparation for hybrid SIWAP/SIMGAP (Simultaneous Injection of Water and Polymer / Simultaneous Injection of Miscible Gas and Polymer) EOR pilots in ADNOC Onshore.

This paper sheds the light on key operational findings and lessons learnt from the first High Temperature (HT) / High Salinity (HS) polymer injectivity tests conducted by ADNOC Onshore. The initial polymer injection implemented on two wells belonging to large ADNOC onshore reservoirs and their success, allowed the preparation of a pre-qualification process of the Polymer Injection Unit (PIU) and subsequent scale-up with improved features serving the challenging conditions of ADNOC Onshore fields. The preparation of the skid pre-qualifications tests is detailed including Performance Criteria set up, PIU Skid Pre-qualification process, upscaling PIU skid design features for the execution of the multi-well polymer pilot, followed by pre-qualification results, summary & conclusions.

The key outcome of this paper presents a new qualification scheme for deploying polymer injection technologies in the region under high temperature, high salinity and high H2S conditions. It also serves as a key contributor to the EOR strategy in the UAE and represents a vital benchmark for the future polymer EOR implementation across the region with advanced look-ahead on the key performance indicators for similar installations.
Anionic Nanoparticle Based Formulation to Control and Cure Moderate to Severe Losses
Authors: Alyami Noktan Mohammed , Wagle Vikrant , Alyami Abdullah Saleh , Kalgaonkar Rajendra
Published: October 2022

Moderate to severe losses can be treated using the loss circulation composition involving nanomaterial-based dispersion and a chemical activator. The nanomaterial employed is an environmentally friendly type of nanosilica. The composition facilitates delayed gelling of nanomaterial-based dispersion. One key benefit of this technology is that it can place the composition into the target loss circulation zone before the nanomaterial-based dispersion gels up. This ensures that the treatment fluid does not set prematurely before reaching the target zone. It is possible to effectively use the newly developed system up to 300°F.

In this study, experiments have been carried out on three different types of nanomaterials that have varying surface charges and particle sizes. Two of the nanomaterials have negatively charged nanomaterial-based dispersions and particles measuring 5nm and 17nm in size, whilst the remaining nanomaterial has a positively charged nanomaterial-based dispersion and particles that are larger than 17nm. Moreover, two different types of chemical activators have been employed, namely organic and inorganic activators, whilst their impacts on gelling times have also been assessed. The gelling time experiments were carried out at four different temperatures starting from 150 °C to 300 °C with increment of 50 °C in each experiment. This research also examined the impacts of activator concentration and different shear rates on the gelling times of the three nanomaterial-based dispersions, whilst permeability plugging tests were carried out using 2mm slotted disks in order to assess their effectiveness in controlling moderate to severe losses.
Extending the Capability of Electromagnetic Corrosion Inspection Beyond Five Tubulars
Authors: Dai Junwen , Fouda Ahmed , Wang Xusong , Hill Freeman
Published: October 2022

Well completions typically consist of multiple nested tubulars that provide the necessary well structure to ensure integrity for production and to protect the aquifers from contaminants. Monitoring the condition of multiple strings of tubulars is crucial in oil and gas wells and environmental management. For wells that had to drill through multiple pressure regimes, or with geomechanical and geology challenges, or those in highly corrosive environments, the number of well casings may exceed five pipes to provide better protection. Surveillance of pipe integrity in such wells is extremely challenging. A multifrequency electromagnetic pipe inspection tool with multiple transmitter and receiver arrays was designed to accurately estimate the individual wall thicknesses of multiple tubulars. In this paper, we present a workflow to process the measurements and demonstrate the performance of this tool to inspect the integrity of more than five nested pipes.

The tool is based on electromagnetic eddy current principle and comprises multiple transmitting and receiving coil antennas with different spacings and operates in continuous-wave mode at multiple frequencies. To increase sensitivity to outer pipes, receiver coils are placed at larger spacings from the transmitter, and low frequency excitation is used. Feasibility studies show that the measurements are sensitive to the outer pipes beyond the fifth pipe, suggesting the possibility to inspect all nested pipes in one single logging run. An advanced data processing workflow including multi-zone calibration and model-based inversion is executed to estimate the tubulars electrical conductivity and magnetic permeability, wall thickness, and eccentricity. In the process of inversion, a regularization term is added to the cost function to obtain a more accurate solution based on the corrosion profile on the pipes as inferred from the data.

The capabilities of the tool in wells with more than five pipes are demonstrated using synthetic data. The tests demonstrated accurate estimation of the location and severity of corrosion in each one of a multiple pipe configuration. This also reveals that the tool can detect various kinds of corrosion in wells with up to seven concurrent strings of pipes.

This is the first time a corrosion inspection tool is shown to have the capability of estimating the individual thicknesses of well completions with more than five pipes. Such capability eliminates the necessity to pull the tubing and provides a complete picture on the integrity of the well casings. The information provided by this tool can significantly minimize inspection time and cost and improve the overall efficiency of well intervention operations.
Improving Drilling Efficiency through Heterogeneous Formations and Reduce Stick Slip Levels after the Implementation of Self-Adjust Depth of Cut Technology in Oil Well
Authors: Alkhazal Sarah Abdulla , Mahdi Munir Jelal , Barrera Jonathan Lee Quintero , Aljishi Mohannad
Published: October 2022

This paper describes the improved drilling efficiency of 8-1/2-inch PDC bits with self-adjusting depth of cut control technology, and its achievements in minimizing the level of vibrations and meeting directional objectives through heterogeneous formations.

An 8-1/2-inch PDC bit equipped with self-adjusting depth of cut control was selected to improve drilling efficiency and mitigate high level of vibrations encountered through a challenging directional application. This selection was made due to its ability to autonomously adjust the amount of depth of cut control and adapt to the current environment. Observations of drilling and vibration data revealed the benefits of the technology in delivering the directional section through multiple formations with excellent performance and successfully mitigating the different type of vibrations.

The 8-1/2-inch self-adjusting bit was used in three wells to deliver four directional sections. The implemented bit was able to reduce drilling costs by attaining a 10 % improvement in rate of penetration, a 36% reduction in torque variation, and 100% completion of each run with zero NPT. In addition, the adaptive technology significantly reduced stick slip vibration and prolonged downhole tool life by its unique dynamic self-adjusting depth of cut control. A comparison study of the effects of lithology changes on different bit types showed the capability of this unique technology to overcome formation challenges and obtain the best drilling efficiency.

The introduction of the only PDC bit in the industry that can autonomously adapt its level of depth of cut control to the current drilling environment successfully improved drilling efficiency, delivered higher drilling performance, and minimized vibration levels.
First Deployments of Friction Adjustable Stabilizer Technology in the GCC
Authors: Yudhia Denya Pratama , Rabis Philippe , Couzigou Erwan , Al-Marzouqi Adel , Al Ameri Fahed Salem , Ryan Gerry
Published: October 2022

The paper seeks to address the challenges of drilling BHA dysfunction which impacted the drilling performance in Abu Dhabi Offshore. Drilling operations experience vibration and stick-slip which limited the ROP and often led to BHA failure cases. In addition, challenging trip out and casing running were observed which indicated unsatisfactory borehole quality. Enhancement of the drilling BHA is required to reduce vibration and improve borehole quality. In reference to study of Self-Excited Stick-Slip Oscillations of Drag Bits by Thomas Richard in 2001, reducing the amplitude of the vertical oscillations should lessen (if not eliminate) the severity of the coupling between the two modes of vibrations, and therefore, of the self-excited vibrations. This could be achieved by minimizing the upward motion of the BHA, by appropriately increasing the lateral friction between the BHA and the borehole wall. Appropriately means "without affecting too strongly the overall efficiency of the system." Friction Adjustable Stabiliser Technology (FAST) is designed with patented features to achieve the above-mentioned BHA condition. A series of runs with FAST incorporated into RSS drilling BHA were planned. A set of KPIs were put in place to evaluate BHA performance. The drilling BHA was simulated to obtain the optimum tool placement, in collaboration with BHA providers. The drilling results were then analysed and compared with analogue wells to demonstrate the deployment of this technology. The deployment of FAST was conducted in 12-¼″ and 6″ hole sections with a total of 7 runs. FAST was run with various RSS systems with low level of vibration in the majority of the runs and proven to minimize vibration/stick-slip during drilling by acting as the BHA contact point and delivering consistent and sufficient friction. As a result, the drilling BHAs were able to deliver the objective to TD and avoid additional trips due to BHA failure. Borehole quality was evaluated through trip out BHA and casing/tubing RIH performance. There is still room for improvement in trip out performance, as backreaming was still required in most of the runs. However, positive impact to performance of RIH casing or lower completion from good quality borehole drilled by BHA with FAST was confirmed from all runs. The saving from fit-for-purpose BHA design on average is 2 days, considering the average NPT for trip out the BHA. In addition, improvement in trip out performance in 6″ section is 0.4 days. Considering above, total saving from 6″ section is 2.4 rig days. The detailed BHA performance analysis and operation feedback from subsequent wells will be beneficial to assess the suitability of this technology to overcome future drilling challenges.
New Low ECD OCIEF (Organophilic Clay-Free Inverted Emulsion Fluid) Weighted with Manganese Tetroxide Showed Superior Performance in Different Fields: Success Story of Drilling with Ocief in High Overbalance Environment Without Downhole Problems, Stuck Pipe Events and Non-Productive Time
Authors: Wagle Vikrant , Yami Abdullah , AlMoajil Abdullah , Onoriode Michael
Published: October 2022

This paper describes the success of using a new low ECD OCIEF in different Gas Reservoirs at elevated temperatures and with differential pressures up to 4,500 psi. The objective of the paper is to highlight the superior performance of OCIEF during the execution which led in overcoming challenges in such type of environment without compromising performance

This paper describes several applications where the OCIEF has been deployed achieving optimum drilling performance while minimizing the formation damage of the reservoir. Consequent applications showed how the implementation of work methods, best practices and optimized drilling parameters allowed to successfully drill the section without downhole problems and pass the Production Screen Test (PST) and finally allow a proper clean-up while producing the well.

Initial deployment of the fluid system shows the required fluid specifications to properly address the slim hole challenges in high overbalance environment. Field implementation and continuous fluid performance improvements are reported in this paper, showing how the fluid system helped to successfully complete numerous wells in different fields. The versatility of the fluid system in terms of rheological profile and thermal stability and the minimized formation damage characteristics made the OCIEF as the sole non- aqueous fluid solution applied in Gas Reservoirs under extreme overbalance conditions. No more non- productive time has been experienced over the entire drilling campaign performed with OCIEF.

The new low ECD OCIEF (Organophilic Clay Free Inverted Emulsion Fluid) designed a new and enhanced polymer package, without organophilic clay and lignite and with acid soluble manganese tetroxide as weighting agent replaced the usage of water-based fluids without compromising production and with improved performance in extremely challenging gas wells. The proven performance is opening more boundaries for future applications in similar wells.
Foam Assisted Lift Journey in PDO
Authors: Ghaempanah Babak , Al Azri Basel , Veeken Cornelis , Al Rashidi Ahmed , Daraai Thabit , Cruceru Dragos , Al Hasani Said
Published: October 2022

Foam assisted lift (FAL) is one of the common deliquification techniques that is applied in different forms. However, achieving sustainable improved performance in practice from case to case is yet a challenge. This paper shares the journey that PDO has gone through so far in assessing and applying foam assisted lift technology, and the strategy that is emerging from this journey. The paper sheds light on challenges and lessons learned by sharing both successful as well as unsuccessful cases to provide a comprehensive picture. Proper candidate selection as well as selecting different implementation methods for different cases are the key learnings and yet challenges in practice that this paper elaborates on.
Production of Waxy Low-API Oil from Deep Exploratory Well with Hydraulic Lift System - A Case Study
Authors: Kalwar Shuaib Ahmed , Awan Abdul Quddos
Published: October 2022

Heavy oil makes up approximately 15% of the world's remaining oil reserves. It offers opportunities that could be commercially viable and often rejected because of the inherent challenges of production. The main challenges for producing heavy oil include flow assurance, produced water separation and treatment, and additional heat and power requirements. In this project, a deep heavy oil well which did not produce naturally during Drill-Stem-Testing (DST) was efficiently revived using jet pump technology.

This paper presents the successful application during a pilot test in which hydraulic jet pumping technology was installed in a deep exploratory well to lift the heavy 11.5° API oil. The candidate well was a single-string completed well flowed from Sakessar-formation at negligible production rates during DST by nitrogen kick-off. Considering the preliminary testing results, jet pump (JP) technology was recommended as the suitable artificial lift (AL) method. The sliding-sleeve-door (SSD) was deployed as a part of initial completion and downhole JP was fabricated as per SSD dimensions. The pump was installed by slickline in the SSD housing and operated to assess the lifted production.

The light crude oil was used as the power fluid during initial phase of pumping. Later, produced fluid was re-injected for continuous lifting operation. The real-time monitoring was carried out for optimizing the parameters of the pump, such as injection parameters, nozzle-to-throat combination, and horsepower. The results of this pilot project demonstrated the successful implementation of jet pump on heavy oil reservoirs. The candidate well produced at an average rate of 300 BOPD at the injection rate of 2,750 BPD with injection pressure of 2,500 psig using an 11X nozzle-to-throat combination. The SSD JP installation was found to be an ideal method to lift heavy oil from the reservoirs, which did not produce by its natural energy. Further, when the well production will decline in future, operators can easily re-optimize JP performance by retrieving it using a slickline for modifying the nozzle and/or throat and re-adjusting the surface injection parameters. The hydraulic lift system enables the operator to improve production while conducting multiple rigless jobs and saving workover cost.

The key objective of this pilot test was to produce heavy oil with minimal OPEX in a deep well. The successful implementation and outcomes of the project identified dynamic applications of the hydraulic lift system technology. This confirmed jet pump as a proven well activation and lift solution even for low API crude and can be used on global practice.
Enhancing Well Integrity and Well Completion Flexibility with a Remotely Operated Multi-Cycle RFID Sub-Surface Isolation Valve
Authors: Munro Chris , Rodriguez Jonathan , Thain Terry , Di Mario Sabatino , Iglesias Danilo , Dornic Steven
Published: October 2022

Sub-surface isolation valves that form part of the well barrier envelope are required to have the most stringent qualification standards whilst also facilitating flexibility and functionality to complete the well safely and efficiently. By incorporating RFID technology into a hydraulically operated downhole ball valve, oil and gas wells can now be completed using remote electronic communication methods to actuate the barrier valve throughout the completion and well test phase.

The mechanical closure of the isolation valve, which is qualified to API 19v V1 CC classification, after any reservoir treatment can present significant well integrity problems should issues arise. To address this, an RFID microchip was to be incorporated into the work string as a contingency close trigger mechanism, should the shifting tool fail. Surface applied pressure cycles were sent to the isolation valve commanding it to re-open to allow well flow-back. Post well testing, an additional RFID microchip was deployed to the isolation valve to re-close it and form part of the well barrier envelope for P&A operations.

The well was completed and successfully tested by installing a set of completion equipment across the reservoir section. After the completion was installed the isolation valve was closed with a shifting tool isolating the reservoir section which allowed a safe well environment for running the upper completion. Having the electronic contingency option available significantly increases built-in contingency whilst reducing overall risk. With the reservoir isolated the upper completion was installed, pressure cycles were sent from surface to remotely trigger the valve to open. The short and specific sequence means that it is easily applied but hard to inadvertently trigger, therefore improving overall well completion flexibility and efficiency. The micro-hydraulic power technology on-board operates independently of hydrostatic pressure, ensuring that the valve opens regardless of the setting depth.

Once the well flow-back was successfully completed the valve was electronically closed by deploying an RFID microchip into the well for the final time, finalizing the P&A barrier envelope.

In conclusion, the combination of RFID on-demand multi-cycle technology with stringent sub-surface isolation valve qualification standards is now providing the industry with the integrity, flexibility, and reliability that it has long sought after, which adds up to a more robust and efficient well performance.

Shifting tools with built-in electronic triggers, advanced barrier valve qualification testing and high-performance sub-surface isolation valves are critical to well performance and safety within the oil and gas industry. This paper will focus on how these aspects were delivered to a super-major client to enable them to complete their well safely and efficiently.
Successful Through Tubing Perforation in Dual String Completion
Authors: Spagnolo Salvatore , Pollio Pasquale , Cappuccio Pasquale , Baldassarri Gianni , Carpineta Gabriele , Colombo Marco , De Clemente Alfonso , Picciani Alessandro
Published: October 2022

In a dual completed well, a through tubing perforation experience from geologic and reservoir study to job execution, is presented. Job targets have been the maximization of the production gain from one production string and the reduction of possible issues associated to charges detonation for the second string. The success of this job has been crucial for the life of a mature naturally fractured carbonate oil reservoir by opening new production opportunities.

The experience has started with a reservoir study followed by a log acquisition to confirm the geological hypotheses about the lack of production contribution from a level. Once the level potential was confirmed, a review of all the possible technologies available in the market, with related benefits and disadvantages, has been carried out in order to obtain the maximum result in terms of perforation efficiency and minimize the risk to lose integrity or accessibility in the well due to charges detonation. A complete explanation of the overall work flow is provided to clarify all the decision making process.

The first need to find an indication about the production contribution of a cased and cemented level through the hydraulic communication with a second perforated level open to production, can come from noise signals generated from a vertical flow path in formation. In fact, the vertical primary permeability or the natural system of fractures in a carbonate reservoir may represent a likely road to flow. The most suitable technology available to detect this phenomenon is the spectral noise log, which is a precise mean to discriminate about fluid movements in well or near wellbore according to its noise frequency. The second need to increase perforation efficiency and preserve one of the two strings from charges detonation in the second string, can be achieved by identifying a preferential direction at bottom hole and aligning the perforation guns to it. The analysis of real time data acquired through electric wireline from the "Magnetic Orientation Tool" coupled with a downhole electric motor controlled from surface, has allowed to fulfill this task.

The study presented offers a valid workflow to follow for through tubing perforation jobs to restore uneconomic wells life and provides a base for spectral noise log possible uses and innovative tools to add in perforation bottom hole assemblies to have more reliable information for improved job results.
Advances in an Integrated Analysis Workflow of Distributed Acoustic Sensing and Distributed Temperature Sensing for Water Injection Profiling on a Horizontal Well
Authors: Mahue Veronique , Dawson Peter , Jimenez Erick , Al Kiyoumi Ahmed , Al Tamimi Ahmed , Othman Alaa , Correia Gladwin , Alyan Mohand , Parihar Shardul
Published: October 2022

This paper describes advances in an integrated analysis workflow of Distributed Acoustic Sensing (DAS) and Distributed Temperature Sensing (DTS) for water injection profiling on a horizontal well, completed with Limited Entry Liners (LEL). The well is completed as an injector with Limited Entry Liner (LEL), MRC horizontal lateral made of 18 separated zones with packers, each with variable numbers of holes.

DAS and DTS data were acquired on coiled tubing, over an acid stimulation period followed by a water injection period. Previous analysis of the dataset, SPE-203065, focused on DTS warm-back models and highlighted challenges in the process; the use of the DAS data was limited.

Recent re-processing of the data using advanced acoustic signal processing techniques was performed to extract several flow characteristics. Both transient and steady state injection conditions were analyzed:

High-definition low frequency slow strain DAS was extracted over the shut-in to injection transient to compute an initial injection velocity profile as well as a stage level injection distribution across the liners. During steady state flow, acoustic denoising algorithms were applied to the DAS data in order to generate a spectral noise log of high signal to noise ratio (SNR) for the detection of all major injection points. Video animations were generated of spectral noise logs over time, to evaluate the dynamic behavior of the injection profile from start to end. The warm-back DTS data was analyzed for a qualitative assessment of the injection Finally, a quantitative injection profile was computed, and the results were compared against a separate PLT log at both stage and nozzle levels.

The results of the transient and steady state flow analysis converged and showed the highest water intake to occur over the heel-ward stages. The depths of highest rate of change in injection velocity, aligned with the strongest acoustic signals from the enhanced noise log. Inversely, the weaker acoustic outflow activities over the middle and toe sections aligned with the smaller velocity changes. The video animations showed a stable injection profile over time. The qualitative DTS analysis confirmed the overall DAS-based injection profile.

The comparison with the PLT injection allocation highlighted clear differences in the profiles. These are being discussed, as well as the possible causes for the discrepancies.

This analysis demonstrates the strength of an integrated DAS and DTS analysis workflow using both transient and steady state conditions. DAS array processing techniques enabled the extraction of high-definition transient thermal plumes, allowing for an early injection profile, which was further strengthened by high SNR spectral noise logging.
Paleo Structure Reconstruction to Reveal the Phenomenon of Paleo Hydrocarbon Contact- A Case Study on a Three Major Fields Onshore Abu Dhabi
Authors: Elila Abusaa Khalifa , Salahuddin Andi Ahmad , Fadipe Oluwaseun , Syofyan Syofvas , Al-Shamsi Saif Ghanim , Al-Naqbi Shaikha Obaid
Published: October 2022

Hydrocarbon presence has been observed in flank wells much deeper than crestal wells in several onshore fields in Abu Dhabi. To explain this phenomenon the integration of paleo-structural reconstruction, petroleum system analysis, and formation evaluation was used.

Thickness maps were created between the Early Cretaceous Kharaib-2 (KH-2) and several younger formations that represent paleostructure during the key tectonic and hydrocarbon expulsion events. Formation evaluation that integrates various types of logs, mud logs, geochemistry, core description and analysis have been conducted on several recent appraisal flank wells to confirm the presence of hydrocarbon below the Free Water Level (FWL).The formation evaluation, petroleum system analysis, paleo-structural reconstruction were integrated in order to understand the interesting phenomenon of paleo oil presence below the current FWL.

Structural reconstructionshows that various fields have structural crestslocated in the north-east during the Lower Tertiary and remained unchanged during peak hydrocarbon migration inthe Tertiary time.South-west tilting occurred as a result of the Zagros orogeny (Miocene), such that the Lower Tertiary structural crests now lies on the flanks of the fields. As a result of this tilting,hydrocarbon remigration and redistribution occurred and in places oil was replaced by water, but traces of residual oil are still present below the current FWL.This study shows that formation fluid sampling, core and log analysis indicate that the flank wells do not have better reservoir qualities that justify a deeper contact. The study also shows that there is no observed compartmentalization that separates the flank wells with crestal area. Structural reconstruction has explained the poor reservoir properties at the field crest, where it shows that today’s crest wells were flank wells at sometime during structural evolution, and diagenesis was the major playing factor impacting rock quality.
Modelling of the Upper Jurassic Petroleum System, Abu Dhabi: Implications for Play and Prospect
Authors: Fadipe Oluwaseun A. , Aitken John F. , Al-Salmi Huda S. , Laer Pierre V. , Vantala Aurifullah
Published: October 2022

As part of a reassessment of the Upper Jurassic Hanifa and Tuwaiq Mountain (TWQM) formations, regional basin modelling was undertaken on the Jurassic (‘Diyab’) petroleum system of Abu Dhabi to investigate hydrocarbon generation, migration pathways and to confirm the play fairway concept. Specific objectives were: To investigate the source rock kerogen transformation, maturity and generation potential,Assess the expected kitchen area in relation to charge and expulsion timing,Calibrate the model thermally and establish an event chart.

The model was built from surface to the Permian Khuff Formation to provide stratigraphic granularities to better understand the Upper Jurassic petroleum system. Sediment decompaction was modelled to illuminate structural evolution and associated properties through time. A total of 16 and 31 wells were used for temperature/pressure and porosity calibration respectively, to reduce uncertainties in the 3D model.Geochemical data filtering of outliers was performed on over 35 wells with Total Organic Carbon (TOC) data in the Hanifa-TWQM formation. The present-day map was refined with updated GDE maps used to estimate the original TOC maps following Peters et al. (2006) principles.

The model of the Upper Jurassic petroleum system is consistent with measured data including, well calibrated pressure, source rock maturity and temperature data. The original TOC map shows organic richness in the Western part of Abu Dhabi decreasing towards the east. The maturity output shows that from the Late Albian (100Ma) to present-day, the source rock is mainly within the late oil to gas window, showing almost complete conversion of kerogen to hydrocarbon with a transformation ratio of over 95%. Generation of hydrocarbon started as early as 150 Ma (Kimmeridgian), shortly after Hith formation deposition, however, it became significant during the Cenomanian (90 Ma). Simulation results indicate that the kitchen area is located in Western and South-Western Abu Dhabi where the original TOC, deposited in an intra-shelf basin, is highest compared to the upper slope and shelf andlean organic contents towards the east. The main reservoir zone (NNW-SSE shoal belt) is charged from the west with up-dip migration into Hanifa reservoirs both onshore and offshore, with some potential long-distance migration from the North-East Neo-Tethys shelf slope. The constructed petroleum systems event chart confirms the establishment of a working relationship between different petroleum systems elements and processes.

Refined TOC maps honoring environment of deposition as an input helped to improve the confidence in the modelling output that led to the validation of a working play with multiple leads identified. The results helped to subsequently update the play maps. In addition, the parameters generated assisted in de-risking identified leads. This provides a framework for detailed and informed prospect maturation studies.
Novel Approach for Porosity Quantification in Carbonates Using Borehole Images
Authors: Noufal Abdelwahab , Belouahchia Mounir , Amri Mohamed , Belayouni Nidhal , Petrov Alexander
Published: October 2022

Porosity quantification in carbonates rocks represents one of the main challenges in assessing potential carbonate reservoirs. Conventional well logs have low sampling rate and do not allowing to get an accurate porosity distribution. Currently, there are different methods for quantifying secondary and primary porosities by integrating different measurements and logs. Borehole image can solve the carbonate heterogeneity challenge when it comes to quantifying accurately the complex pore system distribution.

Single source of information – borehole image (BHI) is used across the full wellbore to calculate the contribution of matrix and heterogeneities to the total porosity and subdivide it into primary and secondary porosities. BHI is transformed into porosity image using only static image with normalized pixel values. Primary porosity refers to the porosity related to the matrix, while secondary porosity is related to all the heterogeneity regions extracted through the semantic segmentation module. For each row in the static image, pixels are classified as "heterogeneity" if they belong to a heterogeneity region, otherwise they are classified as "matrix". The primary and secondary porosity in the row are calculated as the sum of pixel values in the static image that belong respectively to matrix and heterogeneity, normalized by the total number of pixels in the row.

The technique has been used in this study to quantify the secondary porosity. Since there can be large porosity variation between consecutive rows, the results are presented in terms of a moving average. In this application it was used a window span of 1ft, although this can be changed depending on the length scale of heterogeneities in the borehole images. The outputs of this technique (image total porosity, primary porosity and secondary porosity curves) can be used in an empirical equation to improve permeability calculations, core calibration is required. The technique can give sufficient information to characterize the carbonate reservoirs in cases where the porosity system is dominated by one secondary porosity type, e.g. vuggy porosity or fracture porosity with low clay content and no borehole artifacts and performed with careful selection for the parameters and cut-offs.

Applying machine learning reduced these limitations as depending on using database of many wells characterizing the carbonate reservoirs it could be overcome following limitations in comparison with exciting techniques: The primary/secondary porosity distribution greatly cutoff method selection.Separation is possible to vuggy porosity and fracture porosity.Possibility to separate the isolated vugs from the connected vugs.
Integration of Static and Dynamic Data in Sequence Analysis and Its Application in Oilfield B, Middle East
Authors: An Fuli , Chen Xin , Xiao Dengyi , Li Xiaoliang , Ma Cong , Peng Bo , Zhao Bo , Qi Qunli , Wang Bo , Li Qiang , Liu Caiqin , Gao Xiaoli
Published: October 2022

The sequence stratigraphic framework based on the combination of core, lithofacies and logging curve cycles, sometimes hardly reflect the lithology and sedimentary changes between wells, and is inconsistent with seismic data and production performance. Through the integrated research of core, well logging, seismic data and reservoir engineering, this paper proposed an update method. The new method can effectively solve the geological challenges in exploration and development and provide a reliable geological basis for efficient production of the oilfield.

This method includes the following 3 steps, (1) identify the sequence stratigraphic boundary integrated the core and lithofacies analysis, and establish the well correlation sequence stratigraphic framework. (2) According to seismic and geological calibration, realize mutual constraint between wells and seismic and robust the sequence stratigraphic framework. (3) The sequence stratigraphic framework is optimized by using production dynamic data, which could grab the sequence stratigraphic framework more consistent with the deposition law.

The isochronous sequence stratigraphic framework established by this method in B oilfield of the Middle East truly restores the structural characteristics of the progradational strata of the main production layer in B oilfield, and the sequence boundaries match well between drilling data and seismic data. Under the control of the isochronous sequence stratigraphic configuration, the ambiguous results of the previous division in sublayers according to the lithological isopach were updated, which solved the problems of diachronous oil layer and disordered oil-water relationship in this oilfield. This study also provides an effective isochronous sequence stratigraphic unit for reservoir prediction in exploration and development.

Compared with the previous sequence stratigraphy research method in this area, the new method has two major advantages, (1) It complements the shortage of uncertain between wells and increases the accuracy for uncored interval. Furthermore, this method establishes a real isochronous sequence stratigraphic framework. 2) Combined with production dynamic data, the challenge of diachronous sublayers and confusion of oil-water relationship in the research results are avoided.