Exploration is a high risk business. Hence, available data including those from offset fields have to be analyzed and reviewed critically prior to drilling a well. This becomes especially true in a marginal thin reservoir where innovative drilling and testing strategy would play a key role in deciding commercial discovery of the prospect. Flow rate is one of the basic criteria, inter alia , on which commercial viability of a prospect depends. Conventional testing strategy performed in the vertical well did not yield commercially viable flow rate. Hence, innovative approach was adopted to achieve the desired results. After drilling, multi-disciplinary data should be integrated to finalize the testing strategy, which is critical to announce the discovery to meet the criteria set by the company. Reservoir of interest is a thin clastic reservoir, which could not meet the criteria of flow rate during testing with conventional way even though volume in place assumed to be significant due to large area. After carefully reviewing all data, the flow rates were predicted with the modeling if well will be horizonalized. In order to fully evaluate the prospect, the static and dynamic model of the first vertical well was thoroughly reviewed and re-evaluated. The vertical well was tested comingled with two reservoirs having a two feet dense layer between the two. The well flowed mostly water with traces of oil. A detailed review of the test data revealed that a higher prospectivity layer exists in the overlying thin clastic reservoir above the dense and that the two reservoirs are in isolation. Based on this finding, a modeling was performed to decipher optimal horizontal well length to achieve the flow rate. It was a challenge to geo-steer the well trajectory of horizontal section in this very thin reservoir, which was successfully achieved by an active coordination of an integrated teamwork. An innovative approach was adopted by applying Wireline Formation Tester (WFT) data to confirm dynamic isolation from underlying reservoir, which is predicted to be major water contributor. Optimal horizontal well length was established by analytical model for achieving the best flow rate. The well was drilled successfully with horizontal length of 1400 ft. in thin clastic reservoir and completed with fit-for-purpose completion followed by production testing that achieved the flow rate criteria as predicted in the model. This paper summarizes the processes of: (1) data integration, (2) establishing reservoir segmentation based on static and dynamic data, (3) modeling to predict flow rate and optimal horizontal length, (4) selection of fit-for-purpose completion and (5) addressing challenges and lessons learnt during planning and execution phases.

Development of low-permeable oil reservoirs with complex bedding often requires application of production stimulation methods such as hydraulic fracturing. Success of well stimulation greatly depends on quality of geomechanical and hydraulic fracture models. Several different workflows can be used to build a certain model when the input data available are necessary and sufficient. However, in the absence of some of the key data, it is necessary to use rational assumptions instead, but doing so automatically regards model output as probabilistic. This paper concentrates on steps necessary to constrain initial assumptions made within models and demonstrates the result obtained. We present an integrated workflow used for cross-validation of geomechanical and hydraulic fracturing models based on production history match as a constrain. Relatively thin 35 deg API oil-bearing ∼ 0.3 mD hydrostatically pressurized zone, represented by interbedding of heterogeneous sedimentary layers of gross height of ∼ 15 m out of which about 5.5 m is pay, with argillitic barriers at top and bottom (see Fig. 2 ) has active water-bearing formation 45-50 meters above. Production history available for stimulated horizontal wells has shown a significantly increased water-cut compare to one expected from the zone of interest. Earlier frac company stress models were made by tying pressure gradients - "regional experience" - to gamma ray and SP logs and attributing E, KIc to lithology. These fracture models were consistently showing hydraulic fracture containment by barriers of the target zone and, thus, fracturing into water zone was not viewed as a highly probable cause of an increased water cut. Our target was to resolve the water cut problem by means of geomechanical and retrospective hydraulic fracturing modeling. These two models were initially built on incomplete data due to the absence of: pore pressure measurements mechanical properties (static Young's modulus) from core analysis. The models were then cross validated by constraining on production history while utilizing Young's modulus as variable. PEBI-grid based reservoir simulator is fully coupled with finite difference planar full-3D hydraulic fracturing simulator and allows direct transfer of fracture geometry (conductivity) for multiphase flow simulation.

An active filter cake technology (AFT) was chosen to improve production performance in the tight reservoir following a comprehensive laboratory study to determine formation damage impact caused by previous non-damaging fluids (NDF). The AFT was successfully field trialed on two wells with production improvement vs. acid stimulated offset wells. This paper discusses laboratory data and improved field productivity. It documents reduction of torque/drag with increased rate of penetration without using a lubricant during drilling. Comprehensive laboratory testing to identify origins of deficient production was completed by thoroughly reviewing drilling and completion practices, and completion type implemented. Compatibility of base brine with formation water; formation damage impact of drilling fluids used in reservoir and effectiveness of hydrochloric acid (HCl) solution pumped through coiled tubing to destroy the filter cake constituted the first phase of the investigation. Assessment of several fluids capable of mitigating concerns was performed in the second phase. The optimization and customization of candidate fluids to address all challenges was the third phase. Last phase consisted of field trials and assessment of production results. Testing identified a potential incompatibility of calcium chloride brine and the formation water. The brine was replaced with monovalent halides brine. The previous NDF system exhibited elevated filtrate volume and a high concentration of acid insoluble materials which together significantly impacted productivity. Review of the completion operation and laboratory results proved filter cakes of reservoir drill-in fluids (RDF) cannot be homogenously and entirely removed with HCl solution using coiled tubing. Only less than 50% of the wellbore length can be accessed with coiled tubing and treated with acid. The acid treatment dissolved less than 10% of filter cake when sumulated field conditions in the laboratory. Likewise, the filter cake breaker cannot be implemented on barefoot completion as its volume is totally lost to the formation after breakthrough before complete filter cake dissolution occurs. The study recommended AFT with 100% organophilic bridging materials. The AFT was successfully field trialled in two wells. Post analysis of drilling parameters with AFT exhibits lower torques without addition of lubricant compared to previous fluid along with 186% increase in average rate of penetration which saved 79 hours of ILT/well. Production kicked-off without assistance from lighter fluid (N 2 gas) or stimulation showing promising results compared with near-by wells. The 100% organophilic bridging materials were used for first time in field. It proved acid stimulation can be eliminated for the tight reservoir while improving the oil production rate compared to the offset wells. In addition to inherent productivity improvement characteristics, AFT is appropriate where cheesing and greasing of RDF are common problems with lubricants. AFT demonstrates reduced torque without lubricant addition in extended horizontal deviated wells and excellent production while eliminating post stimulation.

An article presents comparative results of pilot of an innovative blocking pack for well-killing operation – emulsion-suspension system with supercharged nanoparticles (ESS). The ESS is characterized by the following competitive advantages: unlimited compatibility with petroleum reservoir fluids, gases, rocks and well-killing brine, adaptability of specific gravity in a wide range (900-1400 kg/m 3 ), foreseeable rheology, alteration of wettability of rock surface, reversibility of blockage, no harm to downhole equipment, system of oil and gas gathering and environment. The ESS blocking pack pilot was carried out in multifractured horizontal wells under high-pressure (39.5 MPa) and high temperature reservoir conditions (115 °C) of Tortasinskoe oil-gas field, Western Siberia, Russia. The reservoir rock of Tortasinskoe oil-gas field is sandstone, characterized by low permeability (0.001-0.0001 μm 2 ) and porosity (13%). A comprehensive laboratory tests program was executed for ensuring successfulness of the ESS blocking pack pilot in the complicated reservoir conditions of Tortasinskoe oil-gas field. The laboratory tests program included a basic research and specific experiments. The results of pilot confirmed significant competitive advantages of the ESS blocking pack in comparison with a synthetic polymer blocking pack, which was unsuccessfully applied earlier on the same production well. The ESS blocking pack showed high performance for well-killing operation in complicated HPHT reservoir conditions than widely used worldwide synthetic polymer system did not work at all.

Fractures serve as important conduits for subsurface fluid flow and their presence can transform an otherwise unproductive rock formation into an economic hydrocarbon reservoir. Natural fractures have a vivid impact on reservoirs, especially the low perm, as they control the hydraulic flow as conductors (open fractures) or barriers (sealed fractures). Abu Dhabi carbonates are dissected by many fracture clusters, but most of them are sealed, therefore it is critical to investigate, which sets are predicted to reactivate. Hydraulic fracturing in horizontal drilling are the primary enabling technology to gain economical production from the low perm reservoirs. However, fracture parameters are poorly constrained by reservoir data, due to they are subseismic and hard to predict their behaviour through the life-cycle of the reservoir. Addressing the structural patterns and using the geomechanical data along well bores help to assess their roles in production enhancement and sensitivity to hydraulic fractures initiation and propagation. The spatial distribution of microfaults, hybrid fractures and pure opening mode fissures with wide variations in strike appears related to their location with respect to the deformation zones of the nearby fault segments in the reservoirs of Abu Dhabi. Usually not all fracture sets enhancing production and the best approach is to predict those sets that playing these roles. The ability of fractured bedrock to transmit fluids depends upon the physical characteristics of the fractures and opening-mode fractures that make up the fracture system, such as fracture aperture, fracture length, fracture density, fault displacement and gouge thickness. Many of the hydraulically significant fractures at the reservoir scale cannot directly detected, neither by borehole imaging tools nor by seismic imaging. Thus, reservoir characterization, in terms offracture architecture models, are derived from a combination of well data and the factors that control fracture development in carbonate reservoirs of Abu Dhabi. These factors include stratigraphy, rock properties, kinematics, especially orientations and mechanics of fracture growth and principally their relation to the present day in situ stresses. The results showing that, hydraulic fractures propagation is dependent on the natural fractures and bedding planes orientations and the well location relative to the fault segments deformation zones. Understanding and predicting the behavior of fractures involves the identification and location of hydraulically significant fractures. Such fractures are conduits for fluid flow, and are connected to other hydraulically conductive fractures to form conduit systems. Conductive fracture networks may include a large number of interconnected hydraulically active fractures, or may be limited to a very small proportion of the total fractures in the rock mass.

Hydraulic fracturing technology has grown popular with the rapidly increasing development of tight conventional and unconventional reservoirs. A major concern with this technique is the use of large amounts of water in these treatments. The use of water causes many potential damaging issues in the formation and limits the amount that can be saved for future generations. One solution is waterless fracturing treatments, which were developed to reduce or eliminate the need for water in hydraulic fracturing. Hydraulic fracturing treatments consume at least 200,000 gallons of water in conventional wells and up to 16,000,000 gallons of water in unconventional wells. The pumped water must include clay stabilizers to deal with the sensitive clays in the formation. Additionally, using water poses a risk of inorganic scale precipitation near the wellbore. Water can also cause severe emulsions that can lead to emulsion blockage cases. Moreover, there are significant reports of water blockage cases in tight gas wells. Only a mere 10-30% of pumped water flows back after the treatment, with the rest attached to clays, or stuck in the pores due to high capillary pressures. Water-based fluids can also cause alterations to relative permeability, and liquid holdup cases in many gas wells. These issues can certainly increase near wellbore skin and reduce production rates. At the end of the treatment, water still causes issues related to disposal and separation prior to diverting it to the plant. The main challenges in developing waterless fluids include feasibility, environmental friendliness, and effectiveness to stimulate the reservoir. This review will cover the various waterless fracturing methods such as hydrocarbon-based, liquid CO 2 , energized, and foamed fluids (CO 2 and N 2 foams) as well as their advantages and disadvantages. Studies into the properties of these fluids, such as rheology, solubility, compatibility, will also be discussed. Field trials will be examined where applicable. This literature review examines various waterless alternatives to traditional fluids for hydraulic fracturing. From this paper, readers can better understand the nature of waterless technologies and be able to better evaluate these technologies for fracturing purposes.

Coiled Tubing Drilling (CTD) has been growing and developed rapidly through the last two decades. There have been numerous highly successful applications of CTD technology in Alaska, Canada, Oman and the United Arab Emirates (Sharjah Sajaa and Dubai Murgham fields), among other places. Currently, Saudi Arabia has undertaken a campaign for the last seven years that has shown successful results in gas reservoirs. ADNOC initiated a trial Coiled Tubing Underbalanced Drilling (CTUBD) project in the onshore tight gas reservoirs in Abu Dhabi, United Arab Emirates beginning operations 1-December-2019. The initial trial will consist of three (3) wells. The purpose of the trial is to assess the suitability of CTUBD for drilling the reservoir sections of wells in these fields, and further application in others. The reason for choosing coiled tubing for drilling the reservoir sections is based upon the high H2S content of the reservoir fluids and the premise that HSE can be enhanced by using a closed drilling system rather than an open conventional system. The three wells will be newly drilled, cased and cemented down to top reservoir by a conventional rig. The rig will run the completion and Christmas tree before moving off and allowing the coiled tubing rig to move onto the well. The coiled tubing BOPs will be rigged up on top of the Christmas tree and a drilling BHA will be deployed through the completion to drill the reservoir lateral. The wells will be drilled underbalanced to aid reservoir performance and to allow hole cleaning with returns being taken up the coiled tubing / tubing annulus. The returns will be routed to a closed separation system with produced gas and condensate being primarily exported to the field plant via the production line, solids sparge to a closed tank or pit and the drilling fluid re-circulated. The primary drilling fluid will be treated water; however, nitrogen may be required for drilling future wells in the field and will be required regardless for purging gas from the surface equipment during operations. A flare will also be required for emergency use and for start-up of drilling. If the trial proves a success, a continuous drilling plan will be put in place.

The poor volumetric sweep efficiency for secondary and tertiary oil recovery processes is mainly caused by reservoir heterogeneity, whether sandstone or carbonate reservoirs. Reservoir heterogeneity is usually characterized by permeability anisotropy and permeability contrast of the formation. Because of the problems of permeability anisotropy and permeability contrast of low and high permeable zones, most of displacing agents are injected into the high permeable zone. When the displacing agent is produced from production well, the displacing efficiency is extremely ineffective. In other words, large quantities of oil remain in the low permeable zone, which is un-swept by displacing agent. In this study, we used In-Situ sc-CO 2− Emulsion as a conformance control agent to plug the high permeable zone, and then improve the volumetric sweep efficiency of the low permeable zone in a carbonate formation. To achieve this goal, we studied the effect of two types of conformance control patterns on tertiary oil recovery performance by sc-CO 2 miscible injection for carbonate reservoirs at reservoir conditions. The conformance control patterns are classified as follows: (1) isolated the low permeable zone and opened the high permeable zone, and (2) opened both the low and high permeable zones when a base-gel system was injected into the core plugs after initial sc-CO 2 flooded. Two physical models consisted of carbonate core plugs set up initially to carry out the core flooding experiments of displacing oil and obtained the remaining oil saturation by water flooding as a secondary oil recovery process. The preliminary sc-CO 2 injection was conducted following water flooding to recover the remaining oil after water flooding as a tertiary oil recovery mode. The practice of the conformance control patterns using In-Situ sc-CO 2− Emulsion generated by injecting base-gel system into the core in which had the presence of sc-CO 2 was performed after the preliminary sc-CO 2 injection. The second sc-CO 2 injection was conducted following base-gel system injection. All experiments were under reservoir conditions. The base-gel system used in this study consisted of polymer and surfactant. The experiments of stabilization and apparent viscosity measurement of the base-gel system and CO 2 emulsion were conducted at varying experimental conditions. Based on the results and observations of the characteristics of study on the base-gel system and CO 2 emulsion, core flooding experiments, the practice of the conformance control patterns with in-situ sc-CO 2− Emulsion, and second sc-CO 2 miscible injection, the in-situ sc-CO 2 emulsion was generated successfully in the formation in which was the presence of sc-CO 2 . The volumetric sweep efficiency and oil recovery under the conformance control patterns using in-situ sc-CO 2 emulsion was improved for both physical models. Also, the production performances were compared for both physical models before and after base-gel system injection in this paper.

This paper presents a comprehensive laboratory and field study discussing development, formulation, and application of a new flat rheology drilling fluid system that meets the challenges faced when drilling in an ultradeepwater well environment. The use of this new flat rheology drilling fluid system for the first time in Asia-Pacific Region has created the potential to efficiently drill more challenging deepwater and ultra deepwater wells in offshore Myanmar, Malaysia, and other associated countries. In a deepwater block situated on Myanmar's west coast, conventional synthetic-based drilling fluids (SBM) have been used to drill all the wells to date. During the planning phase of an ultradeepwater well with a water depth of 2,300 m, it was found that the equivalent circulating density (ECD) with a narrow pore pressure and fracture gradient would have increased downhole complications leading to non-productive time (NPT). The main concern was not being able to reach total depth (TD) or successfully setting casing on bottom with the original well design, requiring implementation of a contingency casing and pushing the operational cost over authority of expenditure (AFE). To overcome the challenges, a new flat rheology drilling fluid system was introduced based on ECD challenges and rheology requirements. The initial study of modelled hydraulics showed a significant ECD reduction using a flat rheology drilling fluid system. The first round of laboratory tests exhibited promising results of flat rheology across all temperature ranges and after iterating numerous formulations developed with local seed mud were narrowed down to two final formulations of 1.08 sg and 1.17 sg. The formulation was field trialed with some slight adjustment in chemical concentrations to meet specific field mud properties. The well was drilled successfully with no major variation in ECD or issues related to the large temperature range. Implementing this customized solution combined with precise strategy led to successful results in efficiently completing one of the most challenging wells of the campaign. The paper presents a comprehensive study of the challenges formulating and implementing a new flat rheology drilling fluid system. Additionally, a detailed study on ECD challenges when drilling an ultradeepwater well is also done. The paper also discusses the comprehensive pit management program and required treatment plan for drilling. Finally, the paper aims to compare the existing results with previous drilling techniques, which will assist operators with the future advances in similar fields.

Mass-transport deposits are sedimentary, stratigraphic successions that were remobilized after initial deposition but prior to substantial lithification and transported downslope by gravitational processes as non-Newtonian rheological units (Bingham plastics or dilatant fluids). The deposits are not associated with a specific stratigraphic position. Mass transport complex (MTC) reservoirs currently under study in Colombia, consist of complex mixtures of metamorphic and igneous rocks with matrix porosities in the 3%-6% range, complex mineralogy, strong localized mylonitization effect and naturally fractured. The reservoirs are in the Lower Magdalena Valley hydrocarbon province in northern Colombia. In this context, the objective is to achieve an accurate porosity determination, water, gas, oil saturation computation and natural fracture assessment in an exploration phase, with scarce background on electrical logs response and petrophysical models in these types of environments. In wildcat conditions, the lack of formation properties knowledge is detrimental to achieve a representative formation evaluation and reservoir potential understanding. While this is true even in relatively known geological environments (siliciclastics, carbonates, for instance), in Mass Transports deposits the complexity is even higher, given the mineral mixtures, heterogeneities, poor rock quality, complex tortuosity and complex natural fractures networks, among other challenges. In this paper, we present an open hole advanced formation evaluation approach that enable to assess the tight matrix and the natural fractures systems, at a level not previously accomplished in these types of geological formations. At the matrix, advanced nuclear spectroscopy that does simultaneous time and energy domain measurements was integrated with a high-resolution magnetic resonance with improved sensitivity at short relaxation times. This allowed an archie-independent methodology for assessing gas from a new Fast Neutron Cross Section measurement, followed by liquid hydrocarbon fraction from the total organic carbon log and matrix-corrected porosity from combining hydrogen index and dry weight elemental concentrations. For natural fractures, the integration of borehole images with radial sonic-based dispersion and stoneley analysis, was carried out. The main advantages of the new method for obtaining porosity, mineralogy, archie-independent hydrocarbon saturation in tight matrix and natural fracture assessment are: 1) conversion of fast neutron cross section to gas saturation and dry weight total carbon to oil saturation, done through a simultaneous inversion by solving matrix-porosity-fluids volumes into an elemental analysis, proven to work at low porosities; 2) reservoir quality assessment from a high sensitive and high resolution NMR T2 relaxation; 3) independency of archie equation parameters, typically unknow in wildcat environments; 4) reservoir potential uncertainty reduction; 5) identification of the natural fracture systems that can contribute to fluids production.

This paper summarizes the integrated technical learnings from the successful application of a an Autonomous Inflow Control Device (AICD) in new long horizontal wells producing heavy oil in multiple fields and show the result of extending this technology to the old producers in the field. It details the facts and observations that multidisciplinary authors have captured. The AICD was completed in more than 40 new oil wells in multiple fields. It comprises of mechanical devices installed with the sand face completion, which react in real time to the properties of the flowing fluids, decreasing/delaying the water influx from high productivity zones, promoting increased oil production from other compartments of the formation, therefore, equalizing the drawdown along the horizontal section of the well and performing a dynamic water shut-off operation. The great successful result from new oil wells with this technology AICD opened the door to do few trials in existing producers. The AICD-completed wells showed initial water cut in the range 1% to 2%. Which had reduced significantly in comparison to nearby analogues. The initial net oil rate resulted to be more than 2 times of the expected one, with an acceleration of ~10,000 bbls of net oil during the first month. After the initial production period, the technology is still delaying the aggressive water cut development usually observed in these fields, having provided 2 times the expected net oil rate during the first 3 months, with an acceleration of approximately 20,000 bbls of net oil over this period. It has been concluded that the application of the technology is successful and already deployed as a baseline in all future horizontal wells drilled. Also this technology was tried in old producer wells and already 15 wells completed with AICD completion which shows good reduction in gross/water and increase in oil production in some of the wells by more than 30%. With these successful results, 35 wells from existing producers were planned to be completed by AICD in 2020 from multiple fields. The authors have summarized the results from the AICD deployment and presented it as a practice worth replication in a similar heavy oil environment, due its many benefits in optimizing field development. AICD in new and old wells will be a game changer in all filed to reduce the water and increase the oil.

In a difficult context of low oil prices, current investments are aimed to cash flow maximization through the oil production increase in old reservoirs with complex structures and a lot of technical requirements. In addition, data acquisition requirements for uncertainty reductions is carefully revised on a case by case basis. This is the current situation for Caguan-Putumayo Basin located in the southeast region of Colombia. The targets are Caballos, Villeta and Pepino Formations, consisting in reservoirs composed of sandstones, carbonates, clay types mixtures, organic matter presence and matrix porosities in the ten percent range and below. Most of wells in this field, that were drilled some decades ago, lacks from electrical logging data in Villeta and Pepino formations -nowadays of increasing interest-. This is because in the past the main target was the Caballos reservoirs. In some wells, the only available information is natural gamma ray and a cement bond log. Considering that a representative formation evaluation lies in reliable mineralogy, porosity, saturation and permeability estimation, we carry out a cased hole petrophysics with ultimate available wireline technology. Regarding petrophysical methods, the archie-based approaches are difficult to apply there due to low formation salinity, variable tortuosity and potential wettability changes (in the carbonatic sections). Additionally, due to matrix mineralogy mixtures it is impossible to accurately determine porosity with just nuclear logs and fixed matrix values. Consequently, erroneous porosity means errors in saturation calculation. Besides that, there are a lot of operational constraints caused by the state of old wells. At the beginning of the project, the solution to overcome the limitations described above and fully characterize these reservoirs in cased hole conditions, relied on advanced nuclear spectroscopy measurements accompanied by solid methodology for resistivity and salinity independent hydrocarbon saturation determination and by a multidisciplinary approach to select candidates and improve workover execution. Later in the project timeline, it was possible to incorporate advanced nuclear magnetic resonance logs, which brings valuable information on longitudinal relaxation times distribution (T1) and transverse relaxation times distribution (T2). These measurements, carried out with a new wireline device with sophisticated design and special pulse sequences acquisition strategy, provided with relevant information on rock quality and reservoir fluids analysis. We present preliminary findings on hydrocarbon behavior, enabling to validate the nuclear spectroscopy-derived saturation and the potential capability of those hydrocarbons to be commercially produced. The main advantages of the new approach for tight formation evaluation are: First, the oil saturation determination is a resistivity/salinity/tortuosity - independent approach since it is computed from total organic carbon measurement; Second, the derived oil saturation is consistent with all available data, because conversion of dry weight total organic carbon into oil saturation is performed through a simultaneous inversion of all measurements into matrix-porosity-fluids volumes (ELAN); Third, this method allows to account for all clay dependency and other lithology effects. The hydrocarbon obtained with the spectroscopy-based petrophysical model was benchmarked against cutting descriptions and nuclear magnetic resonance fluids analysis. The integration with advanced nuclear magnetic resonance was an added value to the project, leaving to a new reservoir characterization step which is currently under study. From a production point of view, the implemented solution is robust and assures data in almost any operational conditions, both for new and old cased hole wells. As a result, the applied solution allowed to significantly increase success rate of improved oil recovery (IOR) activities in Putumayo basin.

In the western Abu Dhabi, oil fields have been discovered from the Mishrif reservoir (Cenomanian/Turonian). These fields are found in shoal/reef related stratigraphic prospects and composed of grainstone or packstone around platform margin setting. Regional understanding believes that the in-situ Shilaif mudstone is not mature enough to source the overlain Mishrif. So, it is inferred that the Mishrif reserves were charged from Shilaif kitchen of regional syncline through over 100km lateral migration from south to north. However, this accumulation pattern seems presumptive as little solid evidence was reported and little geochemistry measurement have been done previously. To enhance understanding of the Shilaif source characteristics and figure out Shilaif-Mishrif accumulation rules, cuttings, cores from Shilaif and oil samples from Mishrif & Tuwayil were taken. Subsequently, geochemistry assay, oil-source correlation and related research were carried out. The results shows the in-situ Shilaif has abundant organic content with high TOC, HI and bitumen "A" with low maturity. Tmax of Shilaif mudstone yields an average value of 430°C and calculated vitrinite reflectance about 0.6, which means an early oil generation for in-situ Shilaif source. Oil-source correlation indicates a higher maturity of crude oil in the Mishrif & Tuwayil than the in-situ Shilaif. Furthermore, similarities of biomarkers between Mishrif oil and the Ghurab syncline Shilaif source are proved. All these evidences reveal the lateral hydrocarbon migration and accumulation northwards. For the migration pathway, it is inferred the regional unconformity of TopMishrif plays an important role to transfer the hydrocarbon. In Western Abu Dhabi, truncation or depositional hiatus around TopMishrif are not as pronounced as Eastern Mishrif platform, but obvious exposure as well as leaching evidence could be observed from uppermost Mishrif and Tuwayil through core investigation. Besides, almost all the oil shows in Mishrif concentrate around the interface, which further proves the role of the unconformity. The study on Shilaif source characteristics and hydrocarbon migration mechanism enhances the insight into accumulation rules of Cretaceous Petroleum system in Western Abu Dhabi and would guide the further exploration activity.

Production of shallow gas has presented a unique opportunity to implement a fit for purpose fracturing workflow due to the level of complexity these reservoirs present. Initially acquired logging data including open hole logs, mud logs, wireline pressure measurements and reservoir sampling as well as micro-frac readings confirmed the presence of relatively shallow gas in low permeability rock. Hence introducing fracturing as a favourable method of extraction made it imperative to address the level of complexity within the reservoir, which varied from the presence of anhydrites, extreme heterogeneity, water sensitivity, as well as the fault environment at such shallow depths. Exploring pilot holes and running advanced image logs as well as acoustic measurements along with micro-frac operation, provided critical data for completion design improvement to not only enhance the chances of successful placement, but also increase the overall gas output. The relatively low bottom hole static temperature and pressure, soft rock, heterogeneity and overall immaturity of the reservoir required extensive core flow tests. X-Ray Diffraction (XRD) as well as lithology scanner logs were also used to fully understand the complex mineralogy. A suitable salt tolerant fluid was proposed for fracturing before optimisation as well as the inclusion of fit for purpose acid systems. The workflow also utilised the extensive geomechanical datasets for analyses, as well as incorporating the geological and petrophysical interpretations. This was followed by sensitivity analyses of the fracturing design based on size of stages, stage spacing, cluster spacing, as well as the cement quality. After performing micro-fracturing tests, a one dimensional mechanical earth model (1D MEM) was optimised to enable better understanding the fracture geometry. The workflow also included the use of chemical tracers to qualify the success of each fracturing stage within the target horizontal section. The workflow started with a collaboration between geology, geomechanics, petrophysics, reservoir, as well as stimulation domains, which resulted in the completion of the first horizontal multistage fracturing completion within the targeted shallow gas reservoir. This milestone provided insight into the required planning for future gas wells within the region and has left significant potential for optimisation given the complexity of the reservoir. The consolidation of a workflow to deliver the first shallow gas project in order to extract the initially confirmed gas presence has presented a novel approach to such a niche project. This was initiated by utilising a time-lapse image analysis, petrophysical and reservoir evaluation, and then coupled with the introducing propped fracturing and matrix acidizing to further calibrate log-deduced parameters. A high level of detail in core analysis, as well as micro-fracturing interpretations, have reduced the uncertainty regarding fracture generation, initiation, and fracture extension into the far field in such a shallow and unconsolidated, low temperature and pressure reservoir.

For speeding up the complex fractured reservoir simulating, we have given more attention to reducing runtime and improving efficiency of the solver. In this work, we describe an improved and computationally efficient version of Newton's method, which reduces the non-linear iteration count, increases time steps, and furthermore reduces time spent in nonlinear loops of reservoir simulating. Safeguarded variants of Newton's method which have used in current reservoir simulators cannot guarantee convergence of the solution, especially in highly heterogeneous, detailed and fractured reservoirs. In such simulators time step chopping is often observed. From other hand, with growing complexity, convergence difficulties can lead to considerable losses in computational effort and prohibitively small time steps. For overcoming this problem, an improved and computationally efficient version of Newton's method, which uses higher order terms in the Jacobian matrix in addition to the Newton's basic linear terms to account for cross variable dependencies including a high-tech stable linear solver, is proposed. This scheme leads to a smaller number of non-linear iterations compared to other known commercial simulators with larger time steps. In addition to SPE10 model, an under saturated fractured black-oil reservoir model, including single and dual grid blocks together, with dimension of 124*105*60 grid blocks is used to evaluate the method efficiency, by comparing the results using the known commercial simulator. This heterogeneous model includes the features of hysteresis, gravity drainage, oil-gas surface tension, and moderate aquifer with 8 active production wells which have produced for 24 years. The numbers of time steps are 525 and 2693 for proposed method and the commercial simulator, respectively. The numbers of Newton iterations are 1667 and 9399, and the average time step size is 26.2 and 5.62 days, for proposed method and the commercial simulator, respectively. These results obviously indicate the efficiency of the proposed method in reducing Newton's iterations and accordingly increasing simulation speed. The novelty of the proposed creative method is in reducing non-linear Newton's iterations and increasing time steps which leads to reduced simulating elapsed time, which has never been observed in current simulators.

A giant carbonate field offshore is being redeveloped using extended-reach horizontal laterals, up to more than 20,000 ft. with open-hole un-cemented liners, drilled from artificial islands. Previously, SPE171800 introduced an innovative Limited-Entry Liner (LEL) design that enables high rate aggressive stimulation of these wells by bullheading. These wells provide significant profitability in unit development cost, though it is critical to effectively stimulate the entirety of the long laterals to maximize reservoir recovery. Recently, Sau et al. 2019 presented our first application of real-time fiber optic surveillance during the successful stimulation of a water injection well with a 12,000 ft LEL lateral section. Fiber optic distributed temperature and distributed acoustic sensing (DTS/DAS) data were collected. Qualitative analysis of the real-time data were compared with a subsequent production logging tool (PLT) to confirm the effectiveness of the LEL completion and also the validity of the real-time fiber optic data. This current paper describes the detailed analysis of the DTS/DAS dataset collected and the information that can be extracted from it regarding the effectiveness of the well stimulation. Also presented here is how DTS/DAS can be used to monitor the completion performance during injection; quantitative DTS/DAS analysis provides detailed insight into the acid volume injection into each compartment as well as post-stimulation water injection profile over time and at different injection rates. Recommendations are made regarding how to use the data from future DTS/DAS enabled stimulation jobs to extract the most value from real-time measurements and how permanently installed fiber optic DTS/DAS systems can be used to monitor the health and performance of such extended-reach injection wells.

Generally, appraisal wells are drilled to reduce uncertainty. However, occasionally reserves uncertainties may increase in a heterogeneous carbonate reservoirs specially challenging stratigraphic limit of reservoir facies. Under such circumstance, sometime operators rethink of further investment in the field development when in-place volumes are marginal. The objective of the study is to present how we achieved well design modification and test strategy in a dynamic environment. Optimal well test design, execution and analysis can help mitigate major uncertainties, which were not considered during initial planning phase The subject appraisal well was drilled as a vertical hole in an up dip direction to the first appraisal well. However, Open Hole (OH) and mud log data indicated the reservoir to be tight and in some portion dominated by water flow during sampling even though clear hydrocarbon presence observed in core chips and cuttings analysis. After detailed studies of the available data, a decision was taken to horizontalize the well towards first appraisal well. While drilling, geological barriers were encountered as indicated by the presence of different fluids in the horizontal section. Variable fluid presence (water and oil) posed a challenge with respect to well completion and testing. This paper describes the process of completing the well in an evolving complicating situation and how successful well test design and execution helped to mitigate the uncertainties. OH Logs, Wire Line Formation Tester (WFT) and test data from the studied and existing wells in the area were used to design the well test and interference with first appraisal well in an evolving situation, which is not typically faced in well operations. Hence, the results obtained provide an additional information that helped to conclude variable fluid distribution and its dynamic connectivity to the first appraisal well. Well was completed followed by test as designed and Production Logging Testing (PLT) was conducted to define reservoir contribution. Post well test analysis and comparison with existing WFT and test data from existing well helped to conclude results and address the uncertainties. This paper summarizes the design process, challenges faced in an unexpected variable fluid distribution in the horizontal section and accordingly how well test analysis was performed to conclude the results that helped to take optimal investment decision for the development of this marginal reservoir.

Meeting the gas production target while maximizing the total gas condensate and hence the revenue from condensate reservoirs is one of the key business drivers for an operating company. This paper describes a comprehensive simulation process to strategize production optimization, which helps in meeting the target molar fraction at the delivery point from the overall asset producing from complex reservoirs with varying fluid properties and achieving the overall target of lean gas production. This process uses an integrated approach encompassing the various nodes in a production system, starting from reservoir to the export system to assure a representative and accurate prediction. In the first step, using the representative fluid model and the desired target production from the field, the well capacity-based rates are allocated to the individual production strings. In the second step, a component level optimizer is used to estimate the contribution of each well based on the well production stream composition. In the third and final step, this contributed production figure is fed back to the surface network hydraulic simulator to assess the back-pressure impact on the overall production and the achievable field-target. The objective of maximizing the condensate production was fulfilled considering the provided constraints of operating guidelines, reservoir, wells, and surface facility capacities. Two different scenario runs were put together where the target gas production was achieved while increasing the condensate production by maximizing the condensate specific molar components and minimizing the heavy molar components. The expected condensate production was forecasted to increase by 5% in the scenario. As the predictive hydraulic model is seamlessly integrated with the true field operating conditions, the outlined optimization process ensured that various business-scenarios accurately forecast the system behavior under various operating conditions. In the scenario, the forecast was able to maximize the condensate while meeting the production target within 1% tolerance limit. The outlined approach provides a clear step by step standardized process approach which can be expanded to cater to the other business needs, such as minimizing the H2S for reducing the corrosion problem, minimizing the C7+ components to produce a high-quality condensate. Such a framework based standardized methodology incorporates a seamless integration between the molar composition optimization and the associated hydraulic calculations-based optimization. Solving the both objective optimization functions simultaneously, this approach provides a novel way to address a vital industry business objective.

In the midst of current oil prices, most companies have shifted their focus on cost-constrained policies for hydrocarbon exploitation, thereby making robust subsurface description a real challenge. Developing a reservoir in such scenario is a massive problem. This study presents various engineering algorithms on such a low-resolution and uneven sandstone reservoir, to optimize the development and expected ultimate recovery - while honoring multiple challenges and limitations. This study focuses on a newly discovered formation, in one of the oldest fields in Pakistan. The productive section of the reservoir comprises of sandstone units in beds up to 40 m thick, separated by mudstone intervals; and is interpreted to be deposited in lower progradational intervals of a delta. To date, three different depositions have been identified with two of them in hydraulic communication and one isolated with faults. Since the seismic data has limitations in its resolution; various engineering analyses were carried out, among which the variations in reservoir pressures, GWC and PVT properties played a major role in the identification of partially drained and isolated prospects. The first two successful wells in the isolated compartment were high producers. However, sudden water production (from fractures) loaded up these wells with only 45% recovery from the compartment - very low for a weak-water drive dry gas system. The static and dynamic data set also showed the existence of more Hydrocarbons. Thus, several engineering and geological information, including the re-interpreted Seismic and simulation models, were applied to analyze the possibilities of concurrent sweet spots. Finally, after utilizing multiple algorithms & risk calculations, more wells were drilled - leading to the revelations of two more depositions in the reservoir, which were in hydraulic communication with each other but isolated with the first compartment. This added around 60% more reserves to the current mix of resources. Two more wells are now planned in the reservoir to optimize the field potential in both compartments. This will lead to an additional 23% reserves value, giving an overall EUR of ~83% from these compartments. The main achievement of this study includes the exploitation strategy of a complicated depositional system to optimize a reservoir full of uncertainties. Since the seismic cannot be solely relied upon in such formations; this paper also illustrates the robust engineering models and detailed algorithms to ensure the development of such low-resolution reservoir without incurring major costs. This study offers an innovative approach that can be undertaken to place the wells at optimum locations, along with the utilization of each data set in a more systematic manner to access the, otherwise, undrained locations.

One of the reservoirs in a giant field in onshore Abu Dhabi has been producing for six decades. The reservoir was already saturated at the time of production commencement, with a large oil rim and a gas cap. Both water injection and lean gas injection have been relied upon to sustain production, and will play an even more prominent role for the future development of oil rim and gas cap. Due to the stakeholders’ different entitlements / equity interests in the hydrocarbons originally existed in oil rim area versus gas cap area, it is important to be able to allocate liquid hydrocarbon production and injection gas utilization among the stakeholders, based on a systematic framework. This paper presents a comprehensive comparison of two modeling-based approaches of fluid tracking for condensate allocation and gas utilization – a tracer modeling option in a commercial reservoir simulator, and a full component fluid tracking approach implemented for this reservoir. The component tracking approach is based on the idea that if individual components represented in a fully compositional reservoir model are tracked separately starting from model initialization, one can trace back the source of hydrocarbon production from both gas cap and oil rim. This approach is implemented through the doubling of the number of components in the equation of state fluid characterization – one set of components for the gas cap, and another set for the oil rim. In order to track the net utilization of the injected lean gas, additional components are needed – in this case one more component representing the lean gas, as the injected gas is a dry gas. The results of the comprehensive comparison demonstrate very clearly that these two approaches yield consistent condensate allocation and gas utilization results over the entire life of field (including history match and prediction). For condensate allocation, the hydrocarbon liquid production split depends on how the injected lean gas is tracked. For gas utilization, the injected lean gas must be tracked as a distinct component separate from both oil rim and gas cap components. The comparison also shows that although the tracer-based approach is numerically more efficient with less runtime, the full component tracking approach is simulator agnostic, and therefore can be implemented in any reservoir simulator. In addition, the full component tracking method can be used for cases where injection gas is a known mixture of oil rim and gas cap gas – something the tracer-based option cannot handle. In summary, this paper presents a first comprehensive comparison of the two (2) different fluid tracking modeling approaches, with practical recommendations on modeling-based hydrocarbon liquid production and injection gas utilization allocation in cases where the commercial framework makes such allocation necessary.