Lost circulation is a major contributor to non-productive time (NPT). Any efforts to better understand the factors that lead to it and subsequently identify a suitable cure will translate to tremendous savings of time and money for operators. Conventional materials such as calcium carbonate, nut shells, graphites and fibers are successful in curing many cases of seepage and partial lost circulation. However, there is a practical limit to the concentration of these materials used to combat the most severe losses due to the limitation of pumps and drilling assembly. In porous formations, high fluid loss squeeze pills have seen some success in reducing losses by forming a high compressive strength plug, but these pills do not have a good success rate in large fractures or vugular formations. Such challenges are better addressed by cross-linking pills, but even this solution does not always have a high success rate due to the low compressive strength of the formed plug. The new phase-transforming loss circulation material (PTLCM) was designed to be pumped easily and achieve thixotropic behaviour under downhole conditions, resisting losses in the thief zone prior to setting as a rigid plug with high compressive strength. A setting-control additive ensures the LCM does not prematurely set. The additive is used at a concentration calculated by considering the time required for pumping and the bottom hole temperature (BHT) in the thief zone. After the LCM sets, a high compressive strength solid plug is formed that can resist fluid loss to the formation. The LCM has a high acid solubility of ~95%, making this system a viable option for deploying in reservoir sections, depending on the client requirement and well conditions. This paper describes two recent successful applications deploying this novel technology. Case Study #1: While drilling in sandstone, the well experienced total losses, which presented an immediate challenge to maintain hydrostatic pressure. The operator responded by pumping several conventional pills loaded with a broad particle size range of fibers, granules and polymers. These pills were unsuccessful at healing the losses, so the operator opted to deploy the new technology LCM. The losses were cured successfully with a single application. Case study #2: Wells drilled in the Western Desert have traditionally experienced severe to total losses while drilling fractured dolomite. Frequently, such events have been difficult to cure by conventional means. The only solution has been multiple applications of cement plugs to heal the losses. This case study describes a well with dynamic losses of more than 150 bbl/hr that were healed by spotting one pill through the circulating sub across the thief zone. The losses were successfully cured, allowing the operator to continue drilling.

As the shale development activity in the Permian continues to be strong and oil prices recover, increasing numbers of infill child wells are being drilled as operators want to improve recovery from each section and continue to meet their production targets. However, production data suggests that both parent and child wells suffer from production losses if they are located too close to one another. The cube model concept, which is also referred to as supersize fracturing, was first introduced about two years ago and has been piloted in the Permian Basin. In a cube model, multiple wells, usually more than 30 horizontal wells with five to six wells in each different horizontal layer, are drilled and completed in the same section. Operators produce those wells simultaneously with the objective of mitigating the parent-child effect of unconventional reservoirs. Nevertheless, with all wells producing at the same time and competing for production from the first day, will this benefit ultimate recovery? This question was investigated through comprehensive fracture and reservoir modeling and simulation. A reservoir dataset for the Spraberry Formation in the Permian Basin was used to build a hydraulic fracture and reservoir simulation model. Different field development strategies were studied. Models representing a traditional parent-child scenario with five parent wells completed and produced one year before four infill child wells and a traditional parent-child scenario with five parent wells completed and produced five years before four infill child wells are compared. In these cases, a geomechanical finite-element model (FEM) was used to quantify the changes to the magnitude and azimuth of the in situ stresses from the various reservoir depletion scenarios. Next, a cube model with nine horizontal wells completed and produced simultaneously was analyzed. These three scenarios were expanded to include 19 horizontal wells with the same methodology. This study aims to help operators in the Permian Basin, as well as in other unconventional reservoirs to understand how different field development strategies affect ultimate hydrocarbon recovery and net present value.

One of the keys to successful and environmentally responsible well stimulation programs in coal seam gas development is to establish consistent procedures for the safeguarding, planning and executing activities across multiple wells. The aim of this paper is to show how a novel application of petrophysical program scripting can be used to make the stimulation process more efficient, consistent and compliant across assets with varying requirements. A macro embedded in petrophysical evaluation software applies a series of rules to rank coals by thickness, allocate a series of perforations and stimulation type based upon coal rank and spacing and then produces actionable treatment schedules which are seamlessly implemented in well stimulation operations at well sites. To do this, the macro grades all coals within the well by thickness based upon a cut-off on the density log, with the thickest coal being graded highest. The macro then identifies the top ranked coal and places perforations based on user defined logic, geological information from offset wells, permeability attributes of the target coal layer(s), depth and vertical separation between adjoining coal targets. Based on the stimulation type assigned, a stimulation schedule is generated that includes estimates of fluid volumes, proppant volumes, injection rates, proppant ramp type and stipulates flush conditions (over-flush or under-flush). Coals thicker than a maximum perforation size are perforated in an upper, middle and lower configuration. Most coals are thinner than the maximum allowable perforation interval and so the macro looks up and down the borehole to include thinner coals within a potential perforation window. The system then generates the stimulation schedule as described above. The macro continues to allocate perforations and stimulation schedules for each validated coal interval and sequentially tries to maximise the total target coal interval along the wellbore. Certain environmental constraints are included in the macro logic to maintain local and regional commitments. For example, coal zones in proximity of permeable non-coal layers i.e. interburden are automatically excluded from stimulation. Multiple advantages of this system have been realised including, a) effective QA/QC as outputs can be directly plotted against the well logs giving the user a quick and easy visual check b) actionable instructions that site based teams can execute including exact perforation depths and stimulation schedules c) provide realistic materials and costs estimates that ensure efficient planning and logistics, d) monitor and document any variations between allocated schedule versus actual execution, e) provide estimate of expected net coal connectivity at a well, development package and asset level which feeds into production and recovery forecasts, f) plan future optimisation studies or pilots and g) most importantly offers a consistent, efficient and compliant framework that can be applied across multiple assets, engineering teams and service providers. This paper focuses on capabilities and advantages of using a macro to automate stimulation design allocation for CSG multi-well (>100 wells) assets. Details of individual stimulation designs for Walloons Coal measures are mentioned in other publications ( Kirk-Burnnand et al., 2015 and Flottmann et al. 2018 ) and hence not covered here.

Neutral wet proppant plays a pivotal role in maximizing the flow back of fracturing fluids and the recovery of produced hydrocarbons. An accurate and repeatable contact angle measurements are extremely challenging because of proppant spherical shape and small size. This paper presents a methodology of direct contact angle measurements in spherical particles examined with high strength coated ceramic proppant. 20/40 and 25 HSP non coated proppants were used for the study. Coating material was applied to the proppant sample to obtain non-wetting characteristics. KRUSS Drop shape Analyzer was utilized to measure the contact angle using a modified pendent drop method. Step by step procedure is detailed and possible sources of errors were identified, and recommendations were introduced accordingly. HSP coated proppant showed contact angle measurements of 117-120° and 84-114° with deionized water and hydrocarbon samples, respectively. Ideally, a neutrally wetted surface would have a contact angle of 90°. This indicates that the proppant is neutral to slightly oil-wet. Wetting characteristics are dependent of hydrocarbon type. For instance, Condensate 2 have a contact angle of 102.3° indicating neutral wetting characteristics, whereas Condensate 3 shows contact angle of 84.5° indicating slightly oil-wet character. Geometry of hydrocarbon droplets modified the adhesion tension of oil, nevertheless had insignificant effect with water drops. For example, tripling the droplet size of Condensate 2 and Diesel resulted in increment in contact angle values of 12° and 15°, respectively.

In CO 2 storage projects, CO 2 usually enters the target reservoir at a lower temperature than that of the surrounding rock and its density is increased. The injection temperature affects how much CO 2 can be stored. In this work we investigate the impact of heat exchange during CO 2 injection into the Surat Basin, Australia, using integrated reservoir modelling. We evaluate the aquifer storage and sealing capacities, as well as pressure build up and CO 2 plume migration. Flow simulations of CO 2 injection into the Precipice Sandstone were conducted with injection temperature from 40 to 80°C. The modelling domain consists of the reservoir sandstone, an overlying transition zone (muddy sandstone) and above it, the ultimate seal. The distribution of porosity, permeability and capillary pressure is heterogeneous. Heat exchange between rock and fluids was enabled in the commercial simulator to evaluate changes in fluid properties due to wellbore cooling. The initial temperature was set to 80°C. The injector’s wellbore pressure drop is modelled honouring a constant well head pressure of 15,000 kPa. The maximum allowed bottom-hole pressure is 90% of a thermally reduced fracturing pressure. The viscosity of water and CO 2 increases during cooling of the near wellbore zone; thus, pressure build up grows faster in the case of lower injection temperatures. Although the bottom-hole pressure becomes higher, injection rate is constrained by well head pressure. Heat exchange also increases the density and saturation of CO 2 at the plume edge, which causes a sharper and faster advancing front. Higher pressure in the reservoir forces fluids to migrate to the transition zone, which also reduces its temperature. CO 2 flows preferentially through the lowest capillary pressure channels and is able to permeate slightly into the transition zone. These physical conditions at the bottom of the well (lower temperature and higher pressure) lead to a denser CO 2 plume and a greater mass is stored in the reservoir each year. This work analyses non-isothermal injection of CO 2 into an aquifer using integrated reservoir modelling. It illustrates how reservoir cooling may increase the rate of CO 2 storage and slight migration to the transition zone.

The highly complex geology of the Sichuan Shale gas play, especially in relation to natural fracture systems at different scales, affects the hydraulic completion efficiency and performance. Ant-tracking-based workflows and borehole image data are regularly used to optimize completion campaigns, but bridge-plug-stuck and screen-out risks are still high. The lack of sufficient understanding and accurate identification of the natural fracture systems are the major challenges to address these engineering risks. Surface microseismic monitoring campaigns were conducted over several wells of the Changning field, Sichuan Basin, China. The surface receivers were placed in a radial pattern to record microseismicity generated by hydraulic fracturing. The failure mechanism of all mapped microseismic events (i.e., strike, dip, rake, etc.) was extracted using a moment tensor inversion (MTI) method. Improved understanding of the natural fracture systems and their influence during the hydraulic fracturing process has been achieved by integrating the regional geological data, pumping data and MTI results. Several hydraulic fracturing cases that stimulated near natural fracture systems were investigated. The microseismic monitoring results show that (i) most of the hydraulically induced fractures located in the vicinity of the natural facture or fault did not propagate along the regional maximum stress direction, (ii) the bridge plug got stuck and (iii) screen-out happened frequently in these areas. Moment tensor inversion reveals that (i) the dominant failure mechanism of the natural fractures different from hydraulically induced fractures, (ii) more than one group of natural fractures develop along different directions. Real-time adjustments of the pumping schedule and bridge-plug settings were conducted to reduce engineering risks based on the improved understanding of natural fractures, which proved effective. The innovation of using surface microseismic monitoring results to improve understanding of natural fractures and reduce the engineering risks in real time represents a key step forward to mitigate natural fracture influence and improve the effectiveness of stimulation.

Achieving complete and efficient gravel packing is the primary objective when tasked to install an effective sand control completion. This paper describes the challenges faced during the selection, design, planning and execution phases of the open-hole horizontal gravel pack completions in the "L" field, offshore Republic of Congo. The open hole gravel packs (OHGPs) targeted the most prolific sand to ensure production objectives were achieved with the benefit of a gravel-pack completion. The operator completed two OHGPs with alpha/beta technique for the sand face completion utilizing concentric annular pack screen (CAPS), wire-wrap screens, and a service tool permitting post-gravel pack filter cake clean-up treatments. The accurate selection, modeling, and evaluation of sand control techniques were crucial for completion and production optimization, as well as risk minimization. The service approach had traditionally leveraged upon industry rules of thumb and previous experience, but as the reservoir section length increased and completion configuration became more complex, the error margins tightened and the cost of failure increased such that a more robust design approach was needed. This paper addresses several key factors that must be considered carefully when installing a successful gravel pack completion. The dynamic pressure management becomes critical to maintain the bottom hole pressures within a required range for the successful implementation of the gravel pack. Other factors include designing an optimal screen-wash pipe annulus ratio during alpha-beta wave packing, an optimal alpha wave height, and the use of multiple beta wave packing rates. Results from the preliminary modelling of the gravel pack pumping provided an accurate estimation of the maximum and minimum anticipated pumping rates and pressures. These parameter estimates were generated for the workstring design scenarios and provided guidance for the planned pumping rate adjustment during the gravel packing execution phases. The gravel packed wells achieved pack efficiency greater than 100% based on an estimated 8.5-in. diameter OH. Post completion multi-rate tests concluded potential productivity exceeding the operator's expectations. This paper describes the lessons learned and best practices developed for offshore Congo open-hole gravels packs, which have a very challenging well completion and reservoir scenario. Several proven completion practices are reviewed, with a critical examination of the application of these scenarios for future completion operations in this difficult operating environment. This applied methodology has made significant impact on future field development and increased the production expectations for the asset.

Plug and Perf (PnP) completions have been the most widely used multistage hydraulic fracturing methods in unconventional wells. In a PnP completion, isolation between stages is achieved by setting frac plugs inside the horizontal liner. The number of perforation clusters and perforation holes are designed using limited entry perforating techniques. While PnP is a proven method, there are also some downsides, particularly when considering the inability to pump plugs due to changes in casing integrity and casing deformation occurring in 20-30% of horizontal wells. Casing damage has been increasingly recognized as a challenge to well integrity in active or child wells during multistage hydraulic fracturing. Casing deformation and reduction in casing inside diameter (ID) prevent the use of PnP operations due to frac plugs being unable to pass through deformed casing. Cemented multi-entry ball-activated fracturing sleeves (ME-BAFS) allow users to imitate the limited entry effect of PnP completions while eliminating the need to deploy large OD frac plugs for each stage. The multiple entry points are activated using various-sized frac balls dropped from the surface as the stimulation treatment is pumped, eliminating the need to rig up and rig down between stages. After fracturing is complete, the frac balls either dissolve or are flowed to surface allowing production to begin immediately eliminating through-tubing intervention. The multi-entry ball-activated fracturing sleeves use graduated balls and ball seats to open as many as five sleeves per stage with a single frac ball for increased efficiency. Number of clusters and entry points are calculated based on limited entry techniques similar to PnP. Within this study, two limited entry techniques, PnP and multi-entry sleeve systems, are evaluated using commercial fracture modeling software, and well production modeling to compare the steady-state production between PnP and multi-entry ball-activated fracturing sleeves. Hydraulic fracture modeling is also used to evaluate limited entry perforation design, perf erosion, stress shadowing, and fracture propagation.

This paper presents a case study on usefulness of having geomechanical understanding to avoid drilling risks and minimize costs in a Drilling campaign, Offshore Peninsular Malaysia. Significant drilling issues related to wellbore stability were encountered in the four exploration wells drilled during previous campaigns. The development wells were planned to drill with high inclinations (up to 70 0 ), through weak coal layers and cross major fault. The drilling problems of the offset wells were critically analyzed to understand the mechanisms of failures. A geomechanical model was built using the offset well information. The well-calibrated stress model was then used for the wellbore stability modeling for the planned trajectories. The outcome of this study was used as key input for casing and mud design. With the help of the reccomendations based on this study, six highly inclined development wells were drilled through low pressure and narrow mud window intervals without operational problems. Reducing non-productive time (NPT) for the entire drilling campaign was one of the key focus for delivering the wells safely within schedule and budget. This paper documents the entire workflow and methodologies used for this entire study.

In this case study, high resolution temperature array data, acquired during a Drill Stem Test (DST), were able to identify and quantify flow behind the liner. Quantifying the flow rate behind the liner between the production zones was of significant value to the operator to reduce the uncertainty in the Pressure Transient Analysis (PTA). The high resolution temperature array was deployed clamped to the outside of the Tubing Conveyed Perforating (TCP) guns, which were used to selectively perforate multiple zones. Using wireless acoustic technology the temperature data were transmitted to surface to enable real time feedback during the DST. A novel thermal heat exchange model was built that could take advantage of the high resolution temperature array data acquired during the entire test. The results of the model were compared to the real data to validate the results and provide accurate flow rate measurements of the flow behind the liner in real time during the test. A sensitivity study on the various model input parameters was also carried out to reduce the uncertainty in the thermal model, the results of which are detailed within the paper. Being able to quantify the flow behind the liner allowed the operator to adjust their PTA results and provided a more robust reservoir model. Typical thermal models in the industry are unable to quantify flow behind the liner in this environment. A new thermal model had to be developed that could take into account the complex heat transfer processes and take advantage of the high resolution thermal array data acquired during the DST. Despite the challenging wellbore environment during the test, the high resolution temperature data were used to provide a robust zonal flow confirmation and rate allocation during the flow periods. Whilst Distributed Temperature Systems (DTS) are gaining popularity in the oil and gas industry, typically the current technology does not provide the high resolution required to be able to quantify flow behind the casing. This new model, when combined with high resolution thermal array data, has wide ranging applications not only during the DST but also in long term completions where monitoring well integrity is a real industry challenge.

Megalitres of water with associated dissolved oxygen are injected into shale reservoirs during the hydraulic fracturing process. Pyrite oxidation, if it occurs in-situ , can generate extra H + , thereby dissolving calcite and increasing the salinity of flowback water. The process of calcite dissolution may soften the hydraulic fracture surfaces, resulting in proppants embedment and thus decreasing fracture conductivity for calcite-rich shales. Therefore, it is of vital importance to understand the impact of in-situ pyrite oxidation on fluid-shale interactions, particularly calcite dissolution, to help industry screen and design hydraulic fracturing fluids in shales. Spontaneous imbibition experiments were performed using Marcellus shale samples under three conditions: i) ambient conditions, where the fluid was in equilibrium with atmospheric air throughout the tests, ii) limited O 2 condition, where the fluid was free equilibrated with air in a sealed cylinder and iii) vacuum condition, where the fluid in a sealed cylinder was degassed. The pH and ion concentrations were measured upon completion of the experiments. To further explore how pyrite oxidation affects fluid-rock interactions, we performed geochemical simulations with considerations of mineral dissolution (calcite, albite, quartz, chalcopyrite, pyrite and dolomite), surface complexation and the dissolved O 2 on fluid salinity. The spontaneous imbibition tests show that the salinity of fluids in ambient conditions is higher than the limited or vacuumed saturation fluids, confirming that pyrite oxidation generates H + which would dissolve minerals such as calcite and dolomite. This result is also supported by the observed pH and the concentration of dissolved Ca 2+ . The fluid fully saturated with O 2 has the lowest pH and highest Ca 2+ compared to limited O 2 saturation condition and degassed condition. Scanning electron microscopy analyses show that brine saturation barely affects the morphology and elemental distribution of pyrite at ambient conditions, suggesting that pyrite oxidation plays a minor role in fluid salinity. Geochemical modelling also indicates that although pyrite oxidation can slightly increase fluid salinity, the salinity increment is less than 5% of reported flowback water salinity, confirming that the dissolved O 2 in hydraulic fracturing fluids has a minor effect on fluid-rock interaction thus the salinity increment. This work demonstrates that pyrite dissolution at lab-scale would overestimate the impact of fluid-shale interactions and calcite dissolution in reservoir conditions. We prove that pyrite dissolution in in-situ conditions results in minor implications for fluid-shale interactions and calcite dissolution. Consequently, we limit intrinsic uncertainty of hydraulic fluid design associated with pyrite oxidization especially for calcite-rich shales.

The first hydraulic-jet-fracturing multizone completion application was performed in an offshore high-permeability oil well located in the Bozhong oil field in Bohai Bay, China. A detailed case study is presented, highlighting operational challenges and lessons learned from the offshore multizone completion in the Bozhong field. Most offshore high-permeability oilwell completions in the Bozhong field employ tubing conveyed perforation (TCP) followed by frac-packing as multi-zone completions, which is practical in this field. Unlike conventional multizone frac-pack completions, to run perforation guns, the perforating must be completed first, followed by running isolation packers to complete the multizone frac-packing treatments. For hydraulic-jet-fracturing multizone completions, the hydraulic jetting tools are delivered to the target depth using drill pipe; following that, slurry fluid is pumped through the drill pipe to cut through the casing to create fluid flowing channels, which communicate with the pay zone formation. Lastly, the fracturing operation is completed by pumping both proppant slurry through the drill pipe and cleaning fluid through the annulus simultaneously, which creates dynamic hydraulic diversion as functions of isolation between zones. After completing one treatment zone, the tools are pulled to the next target depth, repeating the procedures, until the entire well is complete. After the fracturing treatment, the operator runs production tubing and other accessories, putting the well into production as usual. A detailed completion design and step-by-step operational procedures were prepared based on well data and work conditions to help ensure the effectiveness and safety of the offshore operation. Although some challenges were encountered during the operation, it was overall successfully performed, and significant performance improvement was achieved. After being in production for months, the candidate well has maintained a longer high-production-rate period than the offset wells completed using conventional multizone frac-pack completions. This hydraulic-jet-fracturing multizone completion has proven successful in the Bozhong oil field. The experiences and lessons learned can help benefit future multizone completion optimization for other similar offshore high-permeability oil wells.

Propellant enhancement is a method of increasing permeability through the application of a transient high pressure event to the target formation. As distinct from hydraulic fracturing, propellant enhancement does not involve the application of chemicals or water and consequently does not present the potential for legacy environmental issues. This paper compares the regulatory aspects of propellant enhancement within the states of Australia and also the differences between environmental impacts. A series of propellant enhancements were undertaken for a suite of gas wells in the Surat Basin, Queensland. Propellant charges in the range 18-30 kg were initiated, with deflagration times in the range 500-1,000 milliseconds. The compliance regime for the transport, storage and use of propellant is established under the state’s Explosives Act 1999 as well as the Petroleum and Gas (Production and Safety) Act 2004 and the Environmental Protection Act 1994 . There are three categories of fracturing used to increase permeability: explosive fracturing; hydraulic fracturing; and propellant enhancement. Explosive fracturing applies a very high pressure transient over a period of a few microseconds and can cause local, radial fracturing but with less desired compaction; hydraulic fracturing applies a lower pressure but over a longer period and with greater surface power, resulting in fractures that can extend 200-300 m, largely in the vertical plane; and propellant enhancement, which applies a mid-range pressure over a period of 10-1,000 milliseconds, resulting in fractures extending tens of metres but with random distribution. Residuals from the deflagration process are nitrogen, hydrogen chloride, water and carbon dioxide. There are no precursors for the BTEX suite and no conditions arising that could produce BTEX. A prime question was to determine whether propellant enhancement is captured under the term ‘hydraulic fracturing’ in states’ regulations across Australia. Propellant enhancement is a technology with very few environmental impacts. Vehicular movements to support propellant enhancement are less than five percent of those to undertake hydraulic fracturing on the same formation. There is no requirement for waste water treatment.

The Greater Enfield Project (GEP) is a challenging offshore oil development, designed to produce from the Laverda Canyon, Cimatti and Norton over Laverda oil fields. Six water injection wells are required to provide pressure support and sweep oil to three production wells in the Laverda Canyon and Cimatti oil accumulations to improve oil recovery. The GEP injection wells are a critical aspect of water flood design in a complex field, new to Woodside and with limited global benchmarks. A specific drilling and completion fluid system (Reservoir drilling fluid, completion fluid and chemical filter cake breaker) combined with a unique clean up and displacement technique have been adopted to provide high and sustainable matrix injection performance. While filter cake breakers have been previously used in the industry, they are typically combined with a flowback for filter cake removals. Filter cake clean up by means of flowback was discounted for GEP due to cost and the inability of some wells to naturally flow during early life. All GEP injection wells were completed in 2018-2019, one of which is globally the longest horizontal water injection well completed to date based on the Rushmore data base. Fieldwide injection commenced in July 2019 with favorable results. This paper summarises the key design aspects adopted to deliver successful matrix injection performance, presents the improvements implemented during offshore execution and provides an insight into the early life injection performance.

The aim of this work is to study shale gas production subject to water blocking in compressible shale. Water blocking is a capillary pressure end-effect causing the wetting phase (e.g. water) to accumulate near the transition from a porous medium to an open medium; in this context, a transition from shale matrix to a hydraulic fracture. Shale is considered a tight porous medium with ultralow permeability, and hydraulic fracturing is essential to obtain economical production. Water is frequently used as a fracturing fluid, but its accumulation at the matrix end-face reduces the gas mobility and can lead to rapid decline of gas production rate. The tight nature of the shale as a porous medium also introduces non-standard flow and storage mechanisms. This work develops a mathematical model that accounts for apparent permeability, compressibility of gas and shale, gas adsorption, Forchheimer gas flow, and multiphase flow parameters like relative permeability and capillary pressure, which depend on wettability. The behavior of the model at steady state production is explored to understand the impact of the various mechanisms.

The fiber-optic distributed temperatrue sensor (DTS) has been used for flow profiling in horizontal multi-stage fractured wells, and there were some reservoir/wellbore coupled thermal models presented by researchers. Although current theoretical models are developed for some certain application scenarios, the industry have realized the great potential of DTS for production prediction in unconventional resources. This paper presents a DTS flow profiling case for a horizontal multi-stage fractured well in tight gas reservoirs with open-hole packer completion scenarios by applying a newly improved theoretical model. In this paper, we started with the conventional semi-analytical wellbore-fracture-reservoir coupled flow/thermal model which have been developed for cased, perforated, and multi-stage fractured wells, and revised it to consider the special feature of openhole packer completion scenario. Since the formation fluid firstly flows through the fracture into the open-hole annular space between formation and the packer liner, then flow along the annular space until meet the frac port on the production pipe, we add a simulation sub-region representing open-hole annular which helps to understand the flow and heat transfer inside it. The presented model successfully simulated the two-fold flow regime caused by the simultaneous flow and heat transmission in the annular space and the production pipe. In each stage, the DTS temperature data possibly show double drops due to Joule-Thompson cooling effects at the fracture and frac port locations if they are not consistent. With the improved mathematical model, DTS monitoring data during a three-rate production test in a horizontal multi-stage fractured well in Erdos Basin of China was simulated and analyzed. The improved model with open-hole packer completion was applied and then the gas rate prediction was accomplished.

The method of micro-sized graded proppant injection has been proposed in the industry to increase the size of the stimulated zone in naturally fractured reservoirs, especially CBM. However, big discrepancies between the modelling results of graded proppant injection and the experimental results have been observed. An analytical model of graded proppant injection with consideration of proppant embedment and deformation is established in this paper, and the influences of proppant embedment and deformation are investigated. An analytical model of calculating the permeability of a fracture filled with partial monolayer proppant is established, and a linear elastic model of calculating proppant embedment and deformation is coupled into it to investigate the influences of proppant embedment and deformation on propped fracture permeability. The influences of proppant embedment and deformation on propped fracture permeability and the optimal proppant packing ratio are investigated. The influences of properties of proppant and rock on propped fracture permeability and the optimal proppant packing ratio are also studied. The graded proppant injection schedules with and without consideration of proppant embedment and deformation are compared and practical understandings are obtained. The results show that the propped fracture permeability is reduced by more than 50% when the embedment or deformation extent reaches 18%. Neglecting proppant embedment and deformation will lead to an under-estimation of 15%-18% for the optimal proppant concentration during graded proppant injection. Proppant diameter has little influence on the optimal proppant packing ratio. Lower Elastic Modulus in the proppant or rock and/or smaller proppant particles leads to a higher optimal proppant packing ratio and lower permeability correction factors. Poisson's ratio of proppant or rock has very little influence on both optimal proppant packing ratio and permeability correction factor. Proppant concentrations at different stages of graded proppant injection with consideration of proppant embedment and deformation are 21.8% higher than those neglecting the two factors. Proppant embedment and deformation must be considered during planning of the graded proppant injection schedule.

During the development of low permeability oil reservoirs, the problems of rapid breakthrough of water, non-uniform water-absorbing of injection well and the low efficiency of water flooding are usual facing. The application of polymer microspheres (PMs) for in-depth profile control is considered to be an effective method to solve these problems. This paper systematically reports a field application case of nanoscale PMs for in-depth profile control in the ultralow permeability oil reservoir. In the paper, the characteristics of static geological and dynamic production of Block A in Changing oilfield are analyzed in detail. Meanwhile, the production history and facing problems of the Block A are clarified. According to the analysis results, the pilot test area for the application of PMs in-depth profile control is selected, and its characteristics are described. Then, a detailed implementation scheme is made for the pilot test area. Finally, according to the evaluation parameters of production wells and injection wells, the performance of PMs in the pilot test area is evaluated. The performance evaluation results show that the application of PMs in the pilot test area is very successful, and the PMs can be used for in-depth profile control in the ultralow permeability oil reservoir. More specifically, the average injection pressure of single well increased by 1.1 MPa, and the average thickness of water absorption layer increased by 1.2 m after PMs injection. The success ratio of in-depth profile control was 37.3%, and the total oil production increment of production wells was 4609.2 t. In addition, comparing the performance of well groups that use the PMs with different calibration diameter, it indicates that the application of PMs with appropriate particle size and the reasonable implementation schemes are critical to the success of in-depth profile control. For the pilot test area, the PMs with the calibration diameter as 300 nm is more suitable.

It has been reported that hydraulic fracturing treatments with smaller cluster spacing and larger fracturing fluids volumes yield better production performance in Permian Basin, Bakken, and Eagle Ford. Degradable diverting agents can play an important role as temporary plugging materials for multiple, tightly-spaced fracturing operations. However, applications of degradable diverting agents are often limited to moderate to high reservoir temperatures. In this study, a new degradable diverting agent is developed for use in low temperature reservoir applications. Butane-diol vinyl alcohol co-polymer (BVOH) which has controllable water solubility is evaluated as diverting agents for hydraulic fracturing treatments. Using a high pressure-high temperature filtration apparatus, filtration properties of BVOH diverting agents are measured for various powder-to-pellet ratios under a range of temperature conditions. Filter media with 1 to 3 mm width slots, that simulate fracture openings, are used for the filtration test. The filtrate properties are evaluated based on spurt losses and filtration coefficients for quantitative evaluation. An analytical diverting agent model that considers swelling of the polymer in water is also developed for evaluating the filtration process of multimodal particles. The experimental results presented in this work indicate that the degradable BVOH materials can be used as effective plugging agents for fracture-like narrow slits. Based on spurt losses and leakoff coefficients obtained under different powder-to-pellet ratios and temperature conditions, the performance of the diverting agents is quantitatively evaluated. The optimum powder-to-pellet ratio for BVOH materials are determined to be 80 to 20. The experimental results also reveal that the degree of BVOH crystallinity provides a dominant effect on the solubility of BVOH powder. The test results also indicate that the diverting agent plug properties started degrading under the temperature greater than 140°F as designed. The BVOH diverting agent developed in this work provides effective diversion effects under low to moderate temperature conditions (e.g., 80 to 100°F). The analytical plugging and bridging model developed in this work, which takes into account swelling properties of the polymer, show very good matches to the experimental results. The degradable diverting agent developed for low temperature applications improve operational efficiency and economics of multistage hydraulic fracturing treatments in shallow reservoirs and operations where immediate fracturing fluid flowback is required. The plugging and bridging model with bimodal particle system developed in this study helps stimulation engineers select and optimize diverting agent material types, particle size distribution, and diverting agent concentration for various well, stimulation, and reservoir conditions.

The Sangomar Field Development – Phase1, located offshore Senegal, will consist of 23 wells targeting stacked reservoirs, with horizontal lengths up to 1,500m. Due to the long drilling campaign, wells are likely to be drilled after first production, targeted for 2023. At the time of drilling, reservoir pressure in these wells will be affected by nearby producers and injectors, which will reduce the mud window in the boreholes, affecting the drillability. Vulnerable wells are identified by a deterministic borehole stability assessment based on mud weight windows and a probabilistic well-by-well analysis of reservoir pressure at the time of drilling. The estimated mud weight windows are unique to each well and a function of completion type, overburden thickness and well azimuth. Capturing reservoir uncertainties within the uncertainty framework results in 216 models which are reduced to a more manageable 20 models for simulation using a distance-based K-medoid algorithm. Maps of maximum depletion and inflation are generated for each of the medoids. With this work, the importance of probabilistically assessing reservoir pressures is demonstrated in the context of developing a robust drilling sequence, highlighting that results can vary significantly depending on the reservoir models used. Potential magnitudes of depletion and inflation in some scenarios are significantly greater than initially anticipated. The combination of borehole stability assessment and probabilistic well-by-well analysis of reservoir pressure allows clear identification of wells at increased risk of borehole stability problems caused by injection or depletion. Subsequently, the drilling sequence is updated to mitigate borehole stability risks by executing potential problem wells prior to first production and prioritising key water injectors, enabling management of post-production depletion while continuing to meet the other objectives such as maximising early production potential. This paper outlines an innovative workflow which captures the range of subsurface uncertainties to define probabilistic impact of depletion and injection on borehole stability. Within the literature we have not seen any examples of depletion and inflation being assessed probabilistically on multiple models or using a map-based format. Depletion and inflation are also often discussed in the context of producing fields, not during the first phase of drilling, as is the case for the Sangomar Field.