Abstract The Ostracod formation in the Awali brownfield is an extremely challenging layer to develop because the tight carbonate rock is interbedded with shaly streaks and the presence of a nearby water-bearing zone. Although the Ostracod formation has been in development since 1960, oil recovery has not yet reached 5% because past stimulation attempts experienced rapid production decline. The current project incorporated aggressive fracture design coupled with a unique height growth control (HGC) workflow, improving the development of Ostracod reserves. The HGC technology is a combination of an engineering workflow supported by geomechanical modeling and an advanced simulator of in-situ kinetics and materials transport to model the placement of a customized, impermeable mixture of particles that will restrict fracture growth. The optimized treatment design included injections of the HGC mixture prior to the main fracturing treatment. This injection was done with a nonviscous fluid to improve settling to create an artificial barrier. High-resolution temperature logging was used before the main treatment to calibrate and optimize the pumping schedule, and fracture geometry was measured independently with an acoustic scanning tool after the stimulation. The high clay content within the Ostracod layers creates a significant challenge for successful stimulation. The high clay content prevents successful acid fracturing and leads to severe embedment with conventional proppant fracturing designs. We introduced a new approach to stimulate this formation with an aggressive tip-screenout design incorporating a large volume of 12/20-mesh proppant to obtain greater fracture width and conductivity, resulting in a significant and sustained oil production gain. The carefully designed HGC technique was efficient in avoiding fracture breakthrough into the nearby water zone, enabling treatments of up to 450,000 lbm to be successfully contained above a 20-ft-thick shaly barrier with small horizontal stress contrast. Independent measurements proved that the fracture height was successfully contained. Wells treated with this optimized workflow produced up to 22,000 bbl of oil within first 8 months with negligible water cut, which significantly exceeded all previous stimulation results in the field. This trial campaign in vertical wells proved that the combination of aggressive, large fracture designs with the HGC method could help unlock the Ostracod's potential. The applied height growth control technique was modified with additional injections and improved by advanced modeling that only recently became available. These contributed to a significant increase of treatment volume, making the jobs placed in the Ostracod some of the world's largest utilizing HGC techniques. The experience gained in this project can be of a paramount value to any project dealing with hydraulic fracturing near water formation with insufficient or uncertain stress barriers.

Abstract Cenomanian carbonate deposits of Shilaif Formation, located west of Abu Dhabi, exhibit a high degree of heterogeneity at multi scales. To characterize this formation and explore its hydrocarbon potential, several geological, petrophysical, and geochemical analyses, including digital rock analysis (DRA), were applied and integrated. A hundred ft of whole core were logged at the surface using dual-energy X-ray CT (DECT) and Spectral Gamma (SGR) to generate bulk density, photoelectric factor, and gamma logs. Based on integration between DECT, SGR, and wireline logs, high-resolution total organic carbon (TOC), brittleness index, and mineralogy logs were generated at a millimeter scale, and representative core samples were extracted. Inorganic and organic geochemical analyses represented by X-ray diffraction, LECO TOC, HAWK pyrolysis, vitrinite reflectance, and hydrocarbons chromatography (SARA) were performed on selected samples to define rock mineralogy, type, and degree of organic matter maturity and chemical composition of the hydrocarbons. Nuclear magnetic resonance (NMR) at native, dry and full-brine saturation conditions, mercury injection capillary pressure (MICP), and crushed rock analysis (CRA) were conducted on selected samples to determine fluid saturations, porosity, permeability, and pore-throat-size distribution. The pore-scale analysis was also performed using argon-ion-milled SEM images to quantify organic matter contents and total, effective, and organic matter porosities. All core data obtained at multiscale were integrated with the wireline and generated high-resolution logs to validate and select optimal horizontal leg landing zones. DECT and SGR logs showed the top of Shilaif is mainly made of calcite, while its bottom is calcitic with minor concentrations of clay minerals and pyrite. Integration between DECT and SGR logs showed the mid and bottom of the formation have high radioactivity attributed to the presence of organic matter in intermediate concentrations and the presence of clay minerals. Pyrolysis analysis indicated a kerogen type I to II with an average Tmax equal to 431°C. Measured and calculated vitrinite reflectance (Ro) was, on average, 0.59, confirming that the kerogen of Shilaif in the area of study falls within the immature to the early mature oil window. Measurements such as CRA, MICP, NMR, and 2D SEM analyses showed that Shilaif has low porosity of approximately 3% on average and very low permeability averaging 0.00057 mD. The 2D SEM images and NMR data confirmed this and revealed that it lacks the porosity associated with the organic matter resulting from its low degree of transformation. Lab data and upscaled petrophysical logs showed that Shiliaf in this field has a low degree of thermal maturity and fall within the early oil window. Integration between core analysis results and wireline data helped understand the Shilaif Formation characteristics and determine its hydrocarbon potential. It also provided additional calibration to the wireline data.

Abstract A countrywide benchmarking of ultimate recovery factor (URF) for oil reservoirs in Kuwait is presented in this study. The results of this study have been useful to support identification of long-term opportunities and have influenced the creation of conceptual development plans for some of the newly discovered prospects of the company. The Kuwait Oil Company (KOC) has a diverse inventory of petroleum reservoirs having a wide range of geologic age, depth, reservoir complexity, and development maturity. This study focused on the reservoir complexity index (RCI) method and global analogs to identify development opportunities and improvements to the URF in the brown and green fields of Kuwait. A customized benchmarking workflow was developed to assess the URF of approximately 100 conventional oil reservoirs. First, a detailed 17-parameter RCI factor and a simplified 7-parameter RCI factor were developed. These two RCI methods were then validated against simulation-estimated URF from waterflood development for the study reservoirs. Next, the two RCI factors were used to benchmark URF for study reservoirs against the company's peers and against global analogs having best practices in operations. Finally, a set of benchmarking dashboards were refined to identify reservoir-complexity concerns, comparisons of company and global peers, and identification of potential upsides or risks in URF. Comparison of higher performing global analogs to the company's reservoirs with similar RCI resulted in identification of additional development opportunities and upsides in URF.

Abstract Sand production in unconsolidated formations during sampling can lead to poor quality of samples being acquired due to plugging of flow lines and sealing issues at the probe. Formation pressure and mobility measurements can also be affected by sand production which may cause plugging inside the tool or at the tool inlet and result in increased operational time. Predicting sanding potential thus becomes critical to achieve both operational and formation characterization objectives, especially in deep-water environments, where operation costs are high. Calculating "Critical Draw Down" (CDD) pressure and predicting the sanding envelope through geomechanical-sanding analysis provide insights critical to successful testing and sampling operation. A fit for purpose geomechanical model has been developed based on petrophysical data along with regional knowledge of geomechanical conditions. With the geomechanical model, analytical sanding evaluation is used to calculate a range of CDD values for the likely testing and sampling points using well logs from offset wells. Logs from the studied well are analyzed in real time to update CDDs. The zones least prone to sand production are identified and prioritized for testing and sampling. The pre-drill sanding risk assessment is also used to optimize operational parameters including selection of the best pump and packer types while the real time updated CDD values is incorporated to limit the flowing (drawdown) pressures during the sampling and testing operations. A case study from a deep-water field in India is highlighted where the mentioned workflow developed post logging for a pilot wellbore has helped to optimize decisions in real time during formation pressure testing and sampling in its sidetrack wellbore, thus adding value to reservoir characterization objectives and reducing nonproductive time (NPT). Based on the pre-drill sanding assessment, CDD was found to be in the range of 0 - 500 psi below the formation pore pressure in some of the sand bodies. Also, a large face packer was recommended to enhance sealing efficiency by increasing the contact area with the formation. Pump rate was regulated during pressure testing and sampling to ensure that the pressure never exceeded the pre-defined CDD values thus preventing sand production. Multiple fluid samples were collected successfully without any plugging. This integration of geomechanical assessment with operation contributed to 32% increase in success rate for good quality pressure testing and acquisition of representative samples in the sidetrack wellbore, benefitted from a systematic adaptation of pre-job assessment and real time optimizations compared to the pilot wellbore. The pre-drill petrophysical and geomechanical evaluations provide critical insights to assist in real time optimization of pressure testing and fluid sampling operations in unconsolidated reservoirs. Workflow presented in this paper has proven to be valuable in obtaining reliable formation pressure data and contamination-free formation fluid samples for accurate reservoir and fluid characterization in unconsolidated formations during wireline logging testing and sampling operations.

Abstract Diffusion forces have been ignored when modeling fluid flow in porous media with a consent belief that viscous transport is the predominant controller. This work introduces a new comprehensive flow model suitable for tight UCRs including viscous, inertia and diffusion forces to account for the transport of fluid in the three scales. A new model addressing multiphase 1-D radial flow in tight UCRs has been mathematically derived and numerically solved, tested and verified against real cases using MATLAB software. A detailed parametric analysis and verification has been carried out and a very clear profiles and flow patterns of the main flow parameters were identified. It has been established that, with lower permeability of the porous medium and lower viscosity of the flowing fluid, the diffusion mechanism becomes more predominant in controlling flow velocity. The results of the newly derived equations that includes the diffusion term have significantly shown the contribution of diffusivity to the flow in the nanoscaled pore spaces as suspected and proven by the numerical models created and the comparison between the suggested equation to other equations and correlations that are used in the field to describe the behavior of the flow in low permeability and low porous medium was established.

Abstract Rate of penetration (ROP) modeling is one of the most important objectives of any drilling program. Penetration model depends on different criteria such as mud weight (MW), weight on bit (WOB), rotary speed (N), and so forth. It is a complex process, because of the high number of variables and uncertainties. Different mathematical models and evaluation methods were developed to solve this problem but they were unable to attain desirable accuracy. Adaptive neuro-fuzzy inference systems (ANFIS) could be used in these cases to predict the rate of penetration. ANFIS is a combination of neural networks and fuzzy logic networks and could be used to create a robust ROP model. The objective of this study is to apply the ANFIS method and compare the modeling results with conventional artificial neural network models. ANFIS trains the model using a set amount of data and then validates it against random data to measure the error. Drill bit record from a certain field has been taken as training data and testing data for the program. The selection process uses the Sugeno model for generating the fuzzy model and the backpropagation and gradient descent method for recognizing the patterns. The data was normalized and sorted out to remove the incomplete values. Tests were done by applying 2 and 3 membership functions to a 4 input interface and a 5 input interface. The accuracy of the results depends on the numbers of inputs and membership functions. Each input was tested with different membership functions to test the data. The output generated from the training process showed that sigmoid function and Gaussian function with grid partitioning and linear output function yielded the best results for 4 and 5 inputs using 2 and 3 membership functions each. The training error recorded was about 3 percent with a checking error of 20 percent for most cases.

Abstract Striving to achieve high level of plant's reliability, and realizing the wide impact of piping misalignment on rotating equipment premature failures, Oil & Gas industry has come up with many standards and best practices aiming to eliminate or minimize to the possible extent the effects of pipe strain on rotating equipment. Pipe strain is considered as one of the most frequent reasons causing rotating equipment to fail. It occurs when there is a misalignment between the piping and the equipment's suction and/or discharge flanges. A case study of a vertical crude charge pump at Saudi Aramco plant, experiencing high vibration and repetitive mechanical seal failures due to piping misalignment and subsequent pipe strain effects will be considered in this paper, highlighting the corrective actions adopted following the relevant investigation and troubleshooting conducted by Operation, Maintenance and Engineering (OME) team. Moreover, a Finite Element Analysis (FEA) model will be presented, demonstrating the significant impact of pipe strain on the pump's shaft behaviour and the potential modes of failure in case pump-to-pipe flanges misalignments are not seriously considered.

Abstract This paper presents the implementation of an integrated reservoir modeling approach that tightly connects and integrates different reservoir modeling disciplines. The approach allows the propagation of subsurface reservoir uncertainties across the various modelling domains, from seismic interpretation though to dynamic reservoir simulation and surface facilities modeling. The results achieved by this approach is a geologically consistent ensemble of runs (100 runs or more) that matches observed data and capable of predicting the future field performance under various development scenarios with a higher degree of reliability. Using an ensemble of runs that first honor the geological facies, as initially defined in the prior probability field, and subsequently updated by reservoir production behavior in the post probability field, enables the user to predict future field performance by allowing hydrocarbon recovery probabilities to be calculated, where the impact of subsurface reservoir uncertainties on prediction results and the possible risk in each development decision is estimated. The field studied is located Offshore in Abu Dhabi and has four main, two secondary, and few minor stacked carbonate reservoirs. Available evidence indicates that the field's reservoirs are not in communication and this study focuses on the main and secondary units. The conceptual geological model proposes that all the zones are conformable, with no truncation or pinching, forming a layer cake depositional model in which reservoirs range in thickness, from few feet in thin zones, to tens of feet in thick zones. Over time the field has been affected by different tectonic stress regimes, resulting in complex strike slip faulting, extending vertically across all reservoirs. Quantification of static and dynamic uncertainties together in the applied methodology is improving the team integration and common understanding for the field structural and geomodelling uncertainties and its impact on the dynamic model behavior for different reservoirs. The methodology has been tested where new drilled well data is included at different times and it showed an easy and quick update for the entire workflow from seismic to simulation. The model was calibrated to historical observed data using different geological uncertainties (structural, facies, geomodelling and dynamic uncertainties) which helped to achieve a geologically consistent and reliable models.

Abstract Carbon-Oxygen ratio measurements are advantageous for calculation of water saturation behind casing in situations where the normal pulsed neutron sigma log fails to do so. Examples include reservoirs stimulated by acids or those having fresh water. Carbon steel casing commonly used to inhibit corrosion processes. In most cases, the carbon content in the steel material is an unknown parameter that can contaminate the accuracy of the C/O measurement. Another challenge, particularly in Abu Dhabi National Oil Company (ADNOC) reservoirs, is the high salinity of the formation water (typically 200 Kppm NaCl) where Chlorine makes more gamma rays per neutron compared to other elements and can interfere with the oxygen accuracy. In this paper, we propose methods and workflows to assure the accuracy of oil saturation from C/O measurements. To lower the dependence on carbon, examples of a process that uses the ratio of the Oxygen window to the total inelastic gamma counts are demonstrated. The responses of other inelastic data including the total inelastic count rate and the ratio of inelastic to capture can be scaled as water saturation as a secondary quality control method. Examples of C/O processing with chlorine corrections are also demonstrated. Data from two wells with consistent reservoir parameters (porosity, rock, wellbore, etc.) are used to demonstrate the proposed techniques. This data is augmented with computer models and analysis to understand the various steps in the workflow. The proposed technique has been applied with acceptable saturation results behind carbon steel in acid stimulated reservoirs, with high salinity water. This paper provides a solution to estimate water saturation behind carbon steel casings in acid stimulated reservoirs and with high salinity water. We have developed workflows as best practices to assure the accuracy of Carbon/Oxygen oil saturation measurements.

Abstract This paper present the successful deployment of the ultra-deep EM tool in a mature carbonate reservoirs to reduce the uncertainty associated with fluid movement for horizontal/ MRC well-placement optimization and enable precise geosteering to maintain distance from fluid boundaries and mapping of nearby reservoirs for future reservoir development. In addition, the EM tool can facilitate to optimise lower completion design liner (blank pipe length, PPL, ICD and swellable packer depth). The high heterogeneity of reservoir qualities increase uncertainty in fluid distribution and make drilling long horizontal, oil producer wells in offshore mature giant carbonate fields very challenging. The usual plan is to drill a pilot hole crossing the reservoir sections, evaluate log saturation, and then re-optimize horizontal sections accordingly. To study the possibility of eliminating pilot holes, an ultra-deep electromagnetic (EM) tool was deployed. The first objective was to detect reservoir boundaries and predict resistivity of the target before penetrating it (Geostopping). The second objective was to optimize the horizontal drain (Geosteering), and map resistivity of adjacent reservoirs for well completion and future well optimisation (Geomapping). Pre-well inversion modeling was conducted to optimize the spacing and firing frequency selection in order to facilitate early real-time geosteering and geostopping decisions. The plan was to run the ultra-deep resistivity tool in conjunction with shallow propagation resistivity and density-neutron porosity while drilling the 8½ in landing section. The objective was to be able to detect the lithology boundary early and predict the resistivity of the reservoir before penetrating, facilitating geostopping decisions. This would allow optimization of the horizontal section to geosteer the well in an oil-saturated layer 4-6 feet from top boundary while geomapping the surrounding reservoirs’ resistivity. The EM tool delivered accurate mapping of thin reservoir layers while drilling the 8½ in section, as well as enhanced mapping of low resistivity zones up to 85 feet true vertical thickness in a challenging low-resistivity environment. Comparison to recorded open-hole logs for validation showed good results, enabling identification of the optimal geostopping point in the 8½ in. section. The EM tool is able to save up to five rig days in the future by eliminating pilot holes. The 6 inch horizontal section was successfully geosteered and placed 4-6 feet from top boundary. The EM tool was able to map reservoir resistivity 30 feet TVD below the wellbore and the completion design was designed accordingly. Additionally, the EM inversion for the nearby reservoirs helped to modify the plans for nearby future wells.

Abstract Oil leakage, due to well integrity issues of varying proportions, from downhole completions is a common phenomenon despite all measures and adherence to regulations. These leakages potentially could cause environmental damage through surface spill, aquifer contamination and in worst-case scenario loss of human lives. In an offshore setting, impact of well integrity issue can be more severe than in an onshore well due to complex and often costly offshore well operations. Downhole completions including cement quality deterioration occurs with the passage of time due primarily to corrosive nature of hydrocarbons produced from a well. Oil companies perform routine well integrity surveillance by acquiring real time annulus pressure data, cement bond, temperature and sonic logs to assess well integrity and perform remedial measures, if and when, required. Leakage may also occur in a complex pattern from nearby wells and different reservoir than the suspected reservoir and show up in the annulus or eventually on the surface. Whilst, well integrity surveillance data indicates leakage when it occurs, finding the exact source location of leakage is often difficult. Objective of this study was to perform a cost-optimized reservoir to annulus leakage oil correlation using geochemical methods in an offshore well to establish the source of oil in the annulus.

Abstract Sanctioning the development of complex carbonate reservoirs and selecting an adequate development plan is not a trivial matter. Understanding formation heterogeneities such as layering, lateral continuity, natural fracture networks, or the impact of faulting are crucial to identify the optimal development strategy. Furthermore, completions strategies can have an outsized impact on the viability of such projects. Those challenges are particularly acute in the Khuff formations offshore Abu Dhabi and detailed formation evaluation is required. An extensive appraisal campaign was performed in Khuff reservoirs, with multiple appraisal wells drilled in different fields. Those wells were evaluated using detailed logging campaigns and then subjected to well tests, usually through drillstem testing (DST) for targeted intervals. Depending on the openhole logs, one to four tests were performed on each well. Multiple objective had to be met: assess formation potential, tie petrophysical properties to inflow sources observed from production logs, perform descriptive pressure transient analysis to understand formation structure away from the wellbore, and assess the optimal completion and stimulation strategy. The interpretation of well tests, combined with advanced petrophysical analysis, formation test data, and production logs, provided a unique insight into the nature of the Khuff reservoirs. A wide range of responses was observed, from tight to highly productive, but not necessarily with clear prior indications of deliverability or inflow intervals. Clear evidence of natural fracture networks or thin highly productive zones were observed, not necessarily correlated to standard logging results. By contrast, other tests yielded more of a matrix-driven flow, even though marked by significant vertical variations. Lateral continuity was also shown to be a possible development challenge, with behavior changing significantly between wells in relative vicinity of each other. This paper will present the observations but also offer some explanations and highlight remaining questions stemming from the analysis of the data acquired. Critically, this will show how the near-wellbore formation characteristics cannot readily yield a clear picture of larger-scale formation behavior and that only actual well testing combined with an appropriate stimulation strategy can unlock formation potential. Observations from the appraisal data over the wide number of wells considered in this study brought a unique insight into the characteristics of the Khuff reservoirs, offshore Abu Dhabi. We highlight their complexity and identify challenges in reliably characterizing them to enable optimal development. This study also shows how well test results can uniquely provide answers not obtainable through other means.

Abstract In order to support a new strategy for the development of the Northern part of a large carbonate reservoir, a multi-disciplinary and comprehensive approach was implemented to resolve the subsurface and surface issues associated with execution of the strategy. The plan is to have a balanced well count per year, optimise the existing geological target in the development plan, propose and implement artificial lift requirement, firm up the need for future Pattern Water Injection schemes. Consequently, a large number of additional producers and injectors is required to be drilled within a highly congested surface and hence the need to embark on Pad drilling to overcome some of these challenges. Pioneering the On-pad drilling in the field enable to increase and sustain the oil production target rate planned in Q1-2021 in addition to convert the Reservoir Development scheme to pattern injection. In order to expedite a robust and effective planning process, a timely and coordinated reservoir monitoring plan was put together and executed to reduce risk of gas for the new wells. In stratigraphically complex areas, pilot holes were recommended to help place and optimize well trajectories in the horizontal section. Key wells were nominated as candidates for accelerated acquisition of pressure and saturation data as critical requirement to understand fluid movement and consequently de-risk new target for the PAD wells. A drilling optimisation exercise which include the following ■ Mapping the target azimuth to the Plat Orientation for ease of drilling ■ Designed wells trajectories with long departure & high turn. ■ Rigorous anti-collision analysis. Very Difficult but detailed well planning process. Wells in area of moderate- high Gas/Water Saturation. ■ Utilisation of advanced completion technology to mitigate unwanted gas & water production. ■ Timely delivery of drilling proposals ■ The wells should be within the minimum recommended safety factor as per company drilling policy. The Cluster Drilling came into execution since January 2019. The main highlighted: ■ Well placement optimization for 24 on-pad drilling wells (8 platforms) by multidisciplinary subsurface integration. Should be available the Flexibility of shortening some wells H.H drain due to risk of high collision with existing wells. ■ Pioneering the On-pad drilling in the norther field successfully completing so far 3 Plats with 12 oil wells on sweet spots in 2019, estimating the associated oil potential in 24 MBPD. ■ Accommodated the required number of wells based on the company production target ahead of time, as per 2018-2023 business plan with the first well commissioning in Q1 2020. ■ To take maximum advantage, during PAD drilling planning process the reservoir monitoring plan should be prepared liaise with the underlying reservoirs, besides, with base on the new data findings allow to introduce changes at least in quarterly base ■ Cost saving was achieved by optimizing Gas Lift completions to 6 out of initially planned 12 wells based on simulation-surveillance integration work. ■ The Integrated Team organisation has worked well resulting in faster and higher quality deliverables

Abstract Oil producing companies are targeting minimal modifications to existing facilities in an attempt to increase oil production with minimal capital investment and squeezed schedule, thereby maximizing overall return on investment. Such brownfield works impose numerous execution challenges which are dependent on availability of shutdown window. This paper focuses on challenges involved in brownfield tie-in execution and presents mitigation strategies for performing tie-ins without production shutdown based on recent projects executed by NPCC. Brownfield projects execution has various constraints due to limitations in design modification of existing facilities. Such limitations pertain to existing Facility Layout, Flare System, equipment and adaptation of new standards to existing facilities and various other design /safety compliance requirements etc. During execution of modification works, early tie-in and shutdown requirements are firmed-up in accordance with the Oil Producing Company's business targets and alignment with all stakeholders. Production shutdown is highly undesirable since it leads to revenue losses as well as schedule and cost implication on the project. Hence, brownfield tie-in strategies always aim to keep production shutdown minimal. In order to accomplish timely tie-in execution, it is necessary to freeze the Tie-in Execution Philosophy at an early stage of the design in compliance with the producing company's HSE standards. This can be achieved by resolving all brownfield related challenges specially ensuring the early alignment of all stakeholders regarding the requirement of early tie-in, plant shutdown and low production window and by conducting an early site assessment to ensure that As-built drawings are corresponding to actual site conditions. In one of the Brownfield EPC projects executed by NPCC, various operational mitigation strategies were considered for tie-in execution without shutdown such as providing a temporary flare relief arrangement during Flare Tie-ins, lowering operating pressure to safe limit during execution of Tie-in on Production Oil manifold with single isolation valve, Isolating Produced water system during low production window and continue production with reduced rate by functioning HP/MP Separator in two phase mode during Produced Water Tie-in, lining up an alternative uninterrupted fuel gas header / source during Fuel Gas Tie-in etc. Such strategic methods resulted in execution of all brownfield tie-ins without any production shutdown, thereby avoiding production loss during modification works in an existing facility. Based on extensive experience with execution of brownfield projects, NPCC is better placed in formulation of tie-in strategies that are aimed at avoiding production loss. This paper presents valuable suggestions and mitigation strategies from recent projects executed by NPCC that will serve as Tie-in execution philosophy for operating companies as well as Contractor companies in petroleum industry. These strategies will assist companies’ in effectively optimizing their resources, enhancing the efficiency and profitability of their projects.

Abstract Deposition of elastic fouling material on equipment for processing and transportation of crude was observed after EOR polymer breaking through to producing wells of the Aishwarya field. The objective of the study included analyzing polymer containing deposits, concluding on mechanism of precipitation and developing the solution for fouling control based on the novel laboratory test procedure. Aishwarya field is in north-west part of India. Fatehgarh group is the main reservoir unit. Artificial lift in Aishwarya is mainly by ESP. An opportunity to improve the recovery of Aishwarya field via better displacement of oil was envisaged through implementation of EOR polymer flood. HPAM (partially hydrolyzed polyacrylamide) polymer injection was initiated in September 2017. Failures of ESP pumps, significant fouling of strainers of liquid transfer and PWRI pumps, pressure increase in Aishwarya production line which necessitate increased pigging frequency was observed soon after polymer breaking through to producing wells. Detailed analysis of produced water containing back produced polymer and elastic deposits collected from different equipment were performed. Specific test methods have been selected for such analysis including SEC, XRF, XRD, SEM/EDS, FTIR, NMR etc. It was found that Aishwarya deposits contain high concentration of precipitated polymer (to 36%) and polymer was completely hydrolyzed, degree of hydrolysis or DOH at 100%. Chemical nature of polymer was evaluated as Calcium Carboxylates. DOH of returned polymer in Aishwarya produced water was measured upto 79%, significant increase from the initial 25%. Such high DOH significantly dropped tolerance of HPAM to divalent cations and increases potential for precipitation with Calcium in Aishwarya brine having relatively high concentration of Calcium and high value of the relative hardness, the ratio of divalent cations to total cations. Fast increase of DOH was attributed to the relatively high temperature of the Aishwarya reservoir (up to 77 deg C at the OWC zone). Novel test method, accelerated aging test, has been used to investigate the long-term stability of the applied HPAM and more thermally stable polymers containing monomers of acrylamide tertiary butyl sulphonic acid (ATBS) for Aishwarya conditions. Laboratory tests represented 200 – 400 days travelling time at the Aishwarya reservoir temperature. The test results indicated on significantly better viscosity retention and higher polymer thermal stability, represented by the polymer cloud point, of ATBS co-polymers than HPAM for Aishwariya field conditions as more suitable polymer type for polymer flooding than HPAM.

Abstract This paper discusses a new technology that helps to identify and differentiate multiple downhole well integrity events - tubing leaks, casing leaks, flow behind casing and overburden integrity, using unique algorithmic pattern recognition capability based on acoustic measurements from Distributed Acoustic Sensing (DAS) data. Here, we demonstrate application of this technology to identify flow behind casing and effectively build remediation strategies for Plug and Abandonment (P&A) of one of the wells in a BP operated field. Applying DAS for tubing leak detection has been discussed in prior publications. The approach has however, relied on simple data processing methods ‘listening’ for zones of increased noise when wells are shut in. In this paper, we discuss results from the application of a novel real time pattern recognition based approach to processing data from DAS that: Denoises data to decouple fluid movement ‘signals’ from background noise Uses signature recognition to constructs fluid ‘flow logs’ across the entire length of the well bore every second; Displays evolution of the fluid noise through depth and time The technology has been deployed across several assets for identifying well integrity events through different stages of well life – starting from drilling, production through to abandonment. In this paper, we demonstrate the application of the new capability for identifying flow behind multiple casing strings on one of the BP operated wells. The system was deployed to identify and pattern the evolution of fluid movement noise behind multiple casing strings through time and depth which was then used in conjunction with a tailored operational workflow to inform effective remediation strategies for plug and abandonment of the well. The fluid flow logs generated were used to conclude on the source of flow, flow propagation and pathway and facilitated an informed decision on extending the well’s first lateral barrier into the formation and adjustment of the position of the planned second barrier. The results showed the effectiveness of the capability in the field and demonstrated its unparalleled value for the operator, allowing for well abandonment. The technology offers a new method of acoustic data processing on DAS that extracts valuable and often hidden insights to identify the source of fluid flow and flow pathways, providing an ability of capturing events behind multiple casing strings – all fundamental challenges that the industry has been looking to solve for several decades.

Abstract In producing oil and gas wells, two-phase flow of gas and liquid is inevitable. Gas density is lighter than liquid density, as a result, gas travels faster than liquid, leaving the liquid phase to build up in pipe segments. The amount of liquid occupying each pipe segment varies. This phenomenon is called liquid holdup, which is defined as the ratio of the liquid volume in a pipe element to the volume of the pipe element. Liquid holdup presents challenges in calculating mixture physical properties and two-phase flow pressure drop. Estimating liquid holdup is the first step to investigate production wells problems. Early detection and identification of liquid holdup ( H L ) in oil and gas wells is needed to reduce the maintenance downtime and thus increase production. This is significantly crucial in designing oil and gas facilities. Consequently, many studies on predicting liquid holdup have been carried out in the past, considering different flow conditions, resulting in a large number of empirical correlations with various degrees of accuracy. Machine learning approaches in predicting liquid holdup in multiphase flows have been recently studied to improve the prediction accuracy compared to the existing empirical correlations. However, these approaches ignored the heuristic feature importance of the input parameters to the predicted H L values. In our study, a machine learning predictive model, boosted decision tree regression (BDTR), is trained, tested and evaluated in predicating H L in multiphase flows in oil and gas wells. Decision trees are considered as non-parametric machine learning models. The datasets used in training and testing the predictive model are experimental and they were collected from literature (111 data-points). Air-kerosene and air-water mixtures were used in obtaining the 111 experimental data-points. Results show that, the proposed BDTR model outperforms the best empirical correlations and the fuzzy logic model used in estimating H L in gas-liquid multiphase flows. For the built model, the most important input feature in estimating H L is the superficial gas velocity ( V sg ). The empirical correlations developed in the past for identifying H L in the multiphase flow phenomenon can only be applied under certain flow conditions by which they were originally developed but this machine learning model does not suffer from this limitation. To the best of our knowledge, the present study is the first work that shows how the decision forest regression predictive models can accurately predict H L . Using the BDTR model with its interpretable representation, one can clearly determine the heuristic feature importance of the input features used in building the model. Heuristic feature importance can help in having a better insight of the issues associated with the H L studies, such as the liquid loading phenomenon.

Abstract Many of the matured fields across the Middle East have formations with below-hydrostatic pressure, when drilling is completed without return to a surface. Most of the losses while drilling across vugular, fractured or weak formations happens suddenly, and a fluid level is not visible at the surface. Further the continuous mud cap is applied while drilling to maintain the constant bottom hole pressure. However, the mud cap flow rate and mud weight (MW) most of the time are based on local best practices and not supported by any engineering study, for example using 1.5 ppg at the rate of 1.5 BPM. To have a proper understanding of the fluid level the bottom hole assembly (BHA) is equipped with an equivalent static density (ESD) sensor was used. As continuous mud cap is required while drilling a special procedure was developed to allow tool application. This study was performed initially across the surface section (which together with an intermediate section often has losses in the Middle East), where based on offset well analysis a single lost circulation zone present and the chance of the well control is low. Based on the result of the study the fluid level was clearly identified. Further, to understand the effect of the mud cap flow rate the section was drilled by changing this parameter. The data obtained allowed to understand the effect of a flow rate on the fluid level in the annulus. Having this information the bottom hole pressure can be maintained with lower and constant mud cap flow rate, avoiding risk of wellbore instability or well control, as well as positive financial impact as expensive mud was not used at a high rate to top up the annulus. The obtained information and knowledge explore further the underground behavior of the depleted, fractured and vugular formations across the Middle East. The manuscript can be used by anyone across the world aiming to improve the service quality and reduce the cost related to mud cap as well as have better knowledge to present the well control risk.

Abstract Monitoring downhole drilling dynamics is an essential element to quality check the measurements provided in logging while drilling (LWD). LWD nuclear magnetic resonance (NMR) is sensitive to the motion induced from the bottom-hole assembly (BHA) during drilling, therefore, quantifying the motion effects becomes important to understand how to correct the measurements. Quantification and correction of lateral motion effects on NMR LWD are the objectives of this paper. Data was collected from various BHA combinations with LWD NMR to model the responses, which were compared with actual downhole conditions to assess the need for the lateral motion correction (LMC). Vibrational assessment criteria are utilized to assign a severity level, which dictates the level of the LMC. The LMC applies an algorithm to differentiate true formation signal responses from the vibration signal response. Specifically, the motion effect function was integrated into the forward matrix of the NMR joint inversion, and a nonlinear optimization algorithm was used to determine the four motion parameters, and if present, compensate for lateral motion effects. In wellbores with severe motion vibration there were large discrepancies between real-time and memory data, which resulted in mismatches with the measured partial porosities. Investigations were conducted on the BHA design, well trajectories, and wellbore environment to quantify the lateral motion effect on the NMR measurement. This information was then compiled to incorporate all aspects of BHA design techniques to mitigate the lateral motion effects on the NMR measurement. The LMC algorithm gives added confidence to ensure all data collected is consistent and reliable even in more challenging wellbore environments, which could be subjected to unanticipated lateral motion. This paper highlights an approach to integrate BHA simulation principles to anticipate severe motion effects during drilling. This knowledge, coupled with the LMC, creates a platform to enhance NMR data quality.

Abstract Objectives/Scope A system providing a standardized and automated approach to rapidly screen and rank large well count assets (hundreds or thousands of wells) in a fraction of the time and repeatably, is proposed. The solution enables the proactive management of existing wells by keeping the production enhancement opportunity pipeline full and expediting potential candidates through the Opportunity maturation process (OMP) in an integrated and collaborative framework. Methods, Procedures, Process The solution is based on a hybrid and automated decision-support system anchored in a knowledge-based framework. Hybrid refers to the integration of (1) petroleum engineering analysis methods and best practices with (2) advanced machine learning algorithms for autonomous well performance signature identification, and (3) the operator's business logic driving the economics of the field. Automated alludes to a continuous running workflow requiring minimal interaction, utilizing machine learning approaches such as neural networks, bayesian belief network models, logistic regressions, advanced optimization, etc. Results, Observations, Conclusions The application of the proposed solution led to workover and intervention candidate evaluations now routinely performed on a weekly basis (compared to the previous bi-yearly approval review and approval process across almost 200 well completions, with engineers confirming and validating the system-generated opportunities before escalating them for approval. Moreover, in its early evaluation, the new system has provided 89% in time savings in both the identification and review of intervention candidates and 88% in cost savings resulting from the elimination of manually tedious and routine work. Novel/Additive Information Asset teams are entrusted with proposing enough well production opportunities on a regular basis. The identification of potential workover candidates remains a manual, tedious and repetitive process consuming several weeks of engineers’ time in every iteration. With the addition of the proposed solution in the existing body of literature, asset teams can proactively manage opportunities in their fields.