bluuebunny/crossref_metadata_2025 huggingface dataset:
Solvent Retrieval During Miscible Flooding in Heterogeneous Reservoirs Using New Generation Nano EOR Materials: Visual Analysis Through Micro Model Experiments
Authors: Cui Jingwen , Babadagli Tayfun
Published: September 2016

Solvent injection has been given attention to enhance oil recovery by sole use or in combination with a thermal method to develop light and heavy-oil fields. To make this process efficient, one needs to retrieve the expensive solvent. This can be achieved by alternative injection of water if the reservoir is homogeneous. In case of heterogeneous reservoirs (fractured carbonates or sands with wormholes), one needs to develop techniques other than viscous displacement to retrieve the solvent diffused into less permeable matrix portion. A method of injecting low temperature steam/water to heat the solvent to vaporize and retrieve it was introduced recently. An alternative is to inject chemical solution to change the wettability and displace the matrix oil/solvent by capillary imbibition. Although it yields lower recoveries, injection of chemical solutions for the same purpose without pre-solvent treatment might be an efficient (more economical) EOR method.

A series of 2-D etched glass micromodel (sandstone replica with a fracture) experiments were designed to investigate the mechanics of chemical injection with and without pre-solvent injection. Conventional surfactants (sulfonate series) as well as new generation chemicals (nanofluids, ionic liquids) were tested for this purpose. After testing and screening effective chemicals without pre-solvent injection, the same chemicals were used to retrieve the solvent and recovery additional oil for pre-solvent injected systems. The micromodel was saturated by dyed processed oils and a selected solvent was injected through the fracture. After the solvent was diffused into matrix completely to recover the oil in it, the model was heated mimicking a thermal method to reach the boiling point of the solvent and retrieve it. Following the heating phase, aqueous phase was injected to retrieve the remaining solvent in the liquid or vapor phase.

Visual observations on chemical flooding process clarified the complex interactions among different phases considering small-scale heterogeneities. This information can help screen promising chemical and determine the efficiency of chemical injection with and without pre-solvent injection for EOR in heterogeneous sands and carbonates.
A Novel Enhanced Oil Recovery Technology Using Dimethyl Ether/Brine: Spontaneous Imbibition in Sandstone and Carbonate Rocks
Authors: Chahardowli M. , Farajzadeh R. , Masalmeh S. K. , Mahani H. , Bruining H.
Published: September 2016

Dimethyl Ether (DME) - augmented brine injection is a novel Shell proprietary enhanced oil recovery (EOR) method. An experimental and numerical study of the enhancement and the acceleration of spontaneous imbibition using DME is carried out, both in sandstone and carbonate limestone cores. The experiments were performed under different boundary conditions using a modified high-pressure Amott cell. The primary recovery with brine from four (weakly water-wet to mixed-wet) sandstone cores, with the top-end, bottom-end, both-ends and all sides open to brine imbibition, was 38-46% of the OIIP. By adding DME, an additional oil recovery of 11-16% of the OIIP was obtained. The primary recovery with brine from the tight limestone cores was only 1-2% of the OIIP. By adding DME to the imbibing brine an additional oil recovery of 43-55% of the OIIP was obtained, which was much higher than the additional recovery from the sandstone cores.

A workflow was considered to model DME-enhanced spontaneous imbibition experiments. The model comprises Darcy's law and the simplified phase behavior of the DME-brine-crude oil system. The model parameters were optimized to match the experimental results. Numerical simulation shows that the oil recovery is more sensitive to the molecular diffusion coefficient and to the partition coefficient, than to the relative permeability and capillary pressure. In the presence of a higher oil saturation in the core, a higher partition coefficient and a higher DME concentration in the aqueous phase, DME/brine imbibition leads to a higher oil recovery.
Development and Rheological Characterization of Suspension of Hollow Glass Beads
Authors: Lumsden Simone , Singh John P. , Morgan Ronnie G. , Hundt Gregory
Published: September 2016

Hollow glass spheres (beads) are widely used as density and rheological modifiers for various oil and gas process fluids, particularly cement. One of the primary uses is to achieve lightweight slurries with good mechanical properties of the set cement. This paper discusses a concentrated yet pumpable suspension of these spheres for offshore cementing applications. Providing the lightweight spheres in a liquid suspension eliminates the risks associated with dry blending these materials. Development of the liquid suspension of hollow beads enables on-the-fly mixing of cement slurries with desired density profiles.

Currently, the beads are premixed in the cement powder before they are shipped to offshore locations, which often results in segregation of the beads during delivery and storage, and limits operations to the predetermined density (concentration of beads) of the slurry. This paper presents the rheological behavior of the concentrated suspension (up to 60% v/v) of hollow glass spheres suspended in a dilute aqueous solution of bentonite and soda-ash. In addition, a patented attachment to the viscometer (called FYSA) was used to characterize the flow behavior. A rheological model was developed to highlight the bead-bead surface interactions as a major component controlling flow behavior.

Four different variants of beads were studied. These were selected to represent a range in surface area per unit volume of beads. Increasing the concentration of beads or the bentonite in solution correlated to increased yield stress and fluid viscosity at operational shear rates. In addition, a Krieger Dougherty-type relation captured well the effect of the bead concentration, with the maximum packing fraction of beads being a function of surface area per unit volume of the beads. Overall, the Herschel-Bulkley (HB) Model best described the suspension rheology with the shear thinning exponent in the range of ~0.8 to 1. Surface area of the beads linearly correlated to the yield stress of the corresponding concentrated bead solution.

Results of this study and the model developed can be used to develop variants of the product with minimal experimentation, thus significantly shortening the development timeline.
Consistent Integration of Drill-Stem Test Data into Reservoir Models on a Giant Field Offshore Norway
Authors: Sætrom Jon , Selseng Harald , MacDonald Alister , Kjølseth Tore , Kolbjørnsen Odd
Published: September 2016

When considering the task of creating reservoir models for fields under development, dynamic data measurements often have limited impact compared with static (geophysical and geological) data. This is not necessarily true for the Johan Sverdrup field offshore Norway, where exceptional reservoir properties make the data from eight drill-stem tests (DSTs) particularly interesting. For this reason, it is important to utilize the information found in the collected static and dynamic data in a consistent manner, to improve the understanding of the reservoir. This is especially true for the Avaldsnes High area, located in the southeastern part of the Johan Sverdrup field, where the observed thickness is below the seismic resolution, and the DST data from four wells indicate permeabilities in the range of 20 to 80 Darcy, with an overlapping radius of investigation.

In this paper, we apply an ensemble-based approach to generate a large set of reservoir models for the Avaldsnes High area of the Johan Sverdrup field, all of which are plausible given the current observed static and dynamic data. We consider multiple modelling scenarios, introducing uncertainty in the sand thickness, facies (rock type) description and the permeability modelling. Unlike conventional pressure transient analysis (PTA), where we analyze the DSTs separately, and the non-uniqueness in the data interpretation is hard to address and quantify, this is not the case with the ensemble-based approach. Since we conduct the static and dynamic data conditioning simultaneously, we can consistently address possible ambiguities in interpreted permeabilities, thicknesses and flow barriers seen in the conventional PTA analysis. The study reveals that by conditioning the generated models to dynamic data we introduce clear spatial trends in both the sand thickness and permeability. In particular, we greatly reduce the potential downside with respect to the sand thickness in the Avaldsnes High area.
Best Practices and Lessons Learned from more than 1,000 Treatments: Revival of Mature Fields by Hydraulic Fracturing in Khalda Ridge, Egypt's Western Desert
Authors: Salah Mohamed , El-Sebaee Mohamed , Batmaz Taner
Published: September 2016

Most of Egypt's Western Desert reservoirs are characterized to have low permeability and heterogeneous, poor rock quality. In the early development stages only layers with high permeability were produced, while the low-permeability, low-porosity layers were not considered economic.

As these high-permeability layers became more mature and declined in production, tight layers became the operator's alternative choice to unlock the enormous amounts of hydrocarbons still present in these rocks and achieve economical production targets from these marginal fields. Hydraulic fracturing technology enabled us to unlock the potential of these challenging layers that were previously considered uneconomical.

Hydraulic fracturing is now a common practice, even pushing extremes such as deeper, high-temperature and high-pressure wells in the Western Desert. The incremental production gains from these challenging layers have encouraged operators to invest. Currently, hydraulic fracturing is routinely conducted for all new production and injection wells and is reconsidered for the old wells.

Completion practices, candidate selection criteria, perforation and design strategies, and workflows were revised to address these new challenging conditions and reservoir complexities with hydraulic fracturing technology. For example, vertical completions were replaced by horizontal multistage fracturing completions to increase the reservoir contact. State-of-the-art software was used to simplify decisions on fracture initiation points across heterogeneous reservoirs. Different technologies, alternative to conventional perforating, were introduced to enhance the proppant placement, post-fracturing production, and operational efficiency. This paper provides a review of hydraulic fracturing in Egypt's Western Desert. The hydraulic fracturing technique has been used to develop mature fields and challenging formations of Egypt since the early 1990s. More than 1,000 treatments targeting low- to medium- permeability rocks were pumped in Khalda Ridge. Correlation between mechanical properties, reservoir properties, essential fracturing design, completions, and operational parameters were established over time to help other operators that intend to apply hydraulic fracturing to their assets. Case histories are also provided, demonstrating different fracturing techniques for extreme conditions. In this paper we detail the progress related to completion practices and technologies to revive the mature fields of Egypt.
First Flowline Scale Inspection in Ghawar Field Using a Robust Infrared Technology Offers a Reliable and Cost Effective Approach
Authors: Al-Ghamdi Abdullah A. , Mohamad El-Zefzafy Ibrahim , Al-Malki Mohammad H. , Al-Mulhim Abdullah A.
Published: September 2016

This paper demonstrates the successful utilization of infrared technology to detect scale adhesion to surface flowlines for the first time in the Ghawar Field in Saudi Aramco history. As part of the Saudi Aramco asset integrity program, several field case studies are presented highlighting a comprehensive evaluation of the technology, tool concept, field test results, and equipment utilization guidelines. The approach of this technology evaluation is to utilize infrared spectroscopy as a mean to study the interaction of infrared light with matter to identify unknown material, which in this case is scale accumulation inside surface production lines. Proof of concept tests were conducted on the field by visiting several wells and utilizing a thermal "infrared" gun pointed toward the production lines to observe the thermal transmission signature through different materials. All tests were conducted in conjunction with actual flowline dismantling to confirm the findings of infrared guns with respect to finding any scale accumulation. The results observed from these field tests has confirmed that infrared technology introduces a robust noninvasive and cost effective approach for massive scale detection when comparing it to the existing practice of flowline dismantling. Comparing the thermal temperature profile of a healthy production line as a base case to those recorded from other lines has revealed the scale accumulation inside flowlines is associated with different thermal signatures indicating the presence of unknown materials beside production fluid and flowline material. It was found that scale build up is generally linked to a dramatic decrease in the flowline and production manifold temperature. Temperature anomalies shown to also be related to scale and/or debris accumulation. This technology provides a smart and efficient tool for an asset integrity monitoring program. Scale accumulation has represented a great challenge for the petroleum industry to overcome and mitigate as it is linked to significant production decline and may lead to flowline blockage.
Proper Planning Supported by Latest Technology Leads to Drilling the Longest 8.5-in. Section in an Extended-Reach Well: Case Study
Authors: Al Dabyah A. A. , Zubairi B. A. , Al Umairin I. S. , Chima J. I. , Kunhiveetil D. , Otaif H. W.
Published: September 2016

Over the last few years, extended-reach drilling (ERD) field development has significantly increased globally, and its benefits are well recognized. ERD techniques are increasingly used to intersect hydrocarbon targets that are difficult to access due to logistic issues. While these wells are challenging to drill, complete, and service, the benefits can be significant. These benefits drive the development of technology and techniques to continuously expand the ERD envelope and increase the complexity of profiles to reach more challenging targets. The directional drilling and evaluation service supplier plays an important role.

Each ERD well has a unique set of challenges. Common to all ERD projects is that many aspects of drilling engineering principles are not only pushed to the limit, but become highly interrelated and sensitive to smaller changes than conventional wells. For this reason, a team approach to planning and executing ERD activities should be considered critical. Each team member should bring to the project relevant experience, knowledge, a range of field-proven technology, and a solid global support structure.

Drilling successful ERD wells in challenging conditions depends on various factors, which include careful planning and use of the latest technology. Planning involves understanding the geological structure, not only within the reservoir section, but also in the overburden where typically most of the time efficiency gains can be achieved. The last step in planning is designing an efficient bottomhole assembly (BHA) based on previous experiences, lessons learned and inputs from various teams. Good planning is supported by use of new technologies, especially tools that give real-time information, enabling quick and informed decisions to ensure safe and efficient drilling in a challenging environment. This paper discusses the planning and decision-making process to drill ERD wells by using latest real-time technologies in drilling challenging wells. This paper describes the experiences and huge success of drilling the longest 8.5-in. hole section in an ERD well, drilled and cased smoothly through challenging formations.
Multiscale Change Characteristics of Chinese Wufeng Shale Under Supercritical Carbon Dioxide
Authors: Zhu Hai-Yan , Tao Lei , Liu Qing-You , Lei Zheng-Dong
Published: September 2016

Objectives/Scope. Waterless fracturing for shale gas exploitation with supercritical carbon dioxide (scCO2) is effective and environment-friendly, which has become an international fascinating research topic. The formers mainly focus on the chemical and physical properties, and microstructure of sandstone, carbonate and shale caprock, rather than the properties of shale gas formation. And the macroscale mechanical properties and nanoscale fracture characteristics of Wufeng shale under scCO2 conditions (above 31.8 °C and 7.29 MPa) is still not clear.

Methods, Procedures, Process. To study multiscale change characteristics of shale under scCO2 condition, the Chinese Wufeng shale crops (upper Ordovician formation) is obtained from Yibin, Sichuan Basin, China. Firstly, SEM and XRD are taken to study the original microstructure and mineral content of shale. Then, triaxial tests with controlled coring angles and gas conditions (immersed scCO2 and N2 for 10 hours) have been carried out on shale φ25 × 50 mm cylindrical specimens for the objective of studying macro mechanical change of Wufeng shale. In addition, SEM and XRD are also conducted after the triaxial tests.

Results, Observations, Conclusions. Some results are concluded as follow. (1) In the SEM figures, the Group 2 (after testing) are similar to the original ones: the tight bedding planes and undamaged minerals (with sharp edges and smooth surfaces) are found in Group 1 (before testing) and Group 2 (before and after testing), which indicating that the triaxial test with N2 can't damage the microstructures of shale. (2) However, the microstructures in Group 1 SEM figures (after testing) are quite different than the others: the bedding planes are damaged, which lefts some connectivity micro-fractures and corrosion holes; the minerals are broken into lots of small debris and left some uneven mineral surfaces. That demonstrates the scCO2 can change the microstructures and make some minerals (e.g. calcite) fracture more easily. (3) A relative content reduction of calcite, dolomite and pyrite have been found in Group 1, significantly. (4) The scCO2 reduce the triaxial compressive strength of shale with a decline of 3.82% to 19.38%. (5) huger fractures in macroscale have been found in the specimens of Group 1, scCO2 and bedding plane lead to the diversities of failure modes.

Novel/Additive Information. The multiscale physical and chemical changes of shale under scCO2 are essential for scCO2 fracturing, scCO2 jet breaking rock and the geological storage of CO2. The complex microscale fractures, the macro decrease of strength in shale are helpful to the seepage and gathering of shale gas, and finally enhance the shale gas recovery.
Nested Optimization - A Practical Approach Delivering Increased Production Opportunities
Authors: Hadjipieris Pieris , Bishop Simon
Published: September 2016

This paper describes the solution formulation that was put in place in order to maximize oil production on fields with complex optimization spaces. The fields considered presented an infinite combination of control settings that could be used to regulate production. As such, the process by which each problem is broken down into elements that can be easily understood and combined, shows the potential of a technique referred to as "Nested Optimization" in the improvement of production in virtually any field around the world.

The process by which optimization is applied in practice is obviously important, as different approaches to the maximization of production may lead to solutions with various levels of robustness, efficiency and practical application in the field. The workflow presented achieves the need from any operator to distinguish between these approaches and select the one that offers maximum production, while at the same time being able to cope with the ever changing nature of field reality from a flow assurance perspective. The fields considered have multiple constraints that operators have to adhere to, such as erosional velocity limits, integrity limits and others. Controls typically relate to chokes on every well along with such parameters as the speed of compressors that feed export pipelines with associated gas. Routing of wells, risers and other systems at surface is yet another control that often needs to be considered. As such, a variety of optimizers were applied, each dealing with a subset of the complete problem. The boundary conditions of each optimization problem in the nested approach were dynamically controlled by higher level optimizers, so that the overall solution is fully consistent.

Formulating the solution in a way that allowed multiple optimizers to work together in a nested fashion meant that a number of very significant optimisation opportunities could be identified. Generally, the implementation of these opportunities would not require significant additional capital expenditure.

The paper discusses the application of Nested Optimization as well as how this can be automatically coupled to an automated quality control process. Workflows that transform the results of the optimizers into settings that operators can easily follow have been implemented. The solution also shows how steady state and transient models can be linked to the quality control of the pipeline stability results. The linking of optimization results to their application in the field means that operators can be confident of a safe implementation of the recommendations made.
3D Downhole Drilling Automation Based on Minimum Well Profile Energy
Authors: Mittal Manish , Samuel Robello
Published: September 2016

With increased well complexity, difficulty matching the actual well profile with the planned well profile increases. This study discusses building a workflow for automating the bottomhole assembly (BHA) to take corrective actions upon detection of a deviation from the planned well path in a 3D coordinate space, and constructing and programming a prototype demonstrating the proposed theory. The corrective paths would be conventional constant curvature curve and unconventional curves, such as catenary and spline, which are proven to be smooth, thereby reducing torque and drag in the well. The main constraint governing the unknown parameters of the corrective path is the minimum well profile energy criterion, which is excellent in terms of producing smooth curves because it minimizes the curvature and torsion of the curve together. Balanced tangential and minimum curvature methods are used for building the corrective trajectory.

Previous work on downhole drilling automation showed that the minimum energy method, compared to proportional, integral, and derivative (PID) control and fuzzy control, where the model was built for 2D and 3D coordinate space by considering conventional constant curvature curves for correction, yields much smoother wellbore trajectories. The work was continued for unconventional well profiles in 2D wells, where spline, catenary, and clothoid curves were used to return the deviated well to the original planned path. This work focuses on building the model to determine the corrective paths based on unconventional curves for wells in a 3D coordinate space. The model first determines the point on the planned path where the bit needs to join and then estimates the best possible path to do so. The whole corrective workflow is demonstrated with a small scale working prototype. Finally, the results of various optimization models obtained by combining different unconventional curves and trajectory calculation methods are compared.
Low Salinity Flooding (LSF) in Sandstones at Pore Scale: Micro-Model Development and Investigation
Authors: Bartels W.-B. , Mahani H. , Berg S. , Menezes R. , van der Hoeven J. A. , Fadili A.
Published: September 2016

Low salinity waterflooding (LSF) is receiving increased interest as a promising method to improve oil recovery efficiency. Most of the literature agrees that on the Darcy scale, LSF can be regarded as a wettability modification process leading to a more water-wet state, although no general consensus on the microscopic mechanisms has been reached. While wettability alteration may be a valid causal mechanism also on the pore scale, it is currently unclear how oil that detaches from mineral surfaces within individual pores connects to an oil bank or finds its way to a producer. In order to establish a link between the pore scale and the Darcy scale description, the flow dynamic at the scale of (networks of) multiple pores should be investigated. One of the main challenges in addressing phenomena on this intermediate "pore network" scale is to design a model system representative for natural rock. The model system should allow for a systematic investigation of influencing parameters with pore-scale resolution whilst simultaneously being large enough to capture larger length scale effects like saturation changes and the mobilization and connection of oil ganglia.

In this paper, we use micro-models functionalized with active clay minerals as model system to study the low salinity effect (LSE) on the pore scale. A new method was devised to deposit clays in the micro-model. Clay suspensions were made by mixing natural clays (Montmorillonite) with isopropyl alcohol (IPA) and injected into optically transparent 2D glass micro-models. By drying the micro-model, the clay particles are deposited and stick naturally to the glass surfaces and remain attached even under flow of high salinity (HS) and low salinity (LS) brines. In a parametric study the dependence of the LSE on the type of oil (crude oil versus n-decane), the presence of clay particles and ageing was investigated.

Our results show that the system is responsive to LS brine as the effective contact angle of crude oil shifts towards a more water-wetting state when brine salinity is reduced. When using n-decane as a reference case of inert oil, no change in contact angle occurred after a reduction in brine salinity.

This responsiveness in terms of contact angle does not necessarily mean that more oil is recovered. Only in the cases where the contact angle change (due to low salinity exposure) led to release of oil and re-connection with oil of adjacent pore bodies, the oil became mobile and oil saturation was effectively reduced. This makes contact angle changes a necessary but not sufficient requirement for incremental recovery by LSF. Interestingly, the wettability modification was observed in absence of clay. Osmosis and IFT were found to be not the primary driving mechanisms of the low salinity response.
Approach towards Establishing Unified Petroleum Data Analytics Environment to Enable Data Driven Operations Decisions
Authors: David Richard Mohan
Published: September 2016

Exploration and Production companies are increasingly instrumenting their fields with the objective to proactively monitor and surveillance of its wells, reservoir, and facilities for safe and better operations. With this scenario, there is ever increase in the volume and variety of data being generated to support workflows such as real time drilling operations, production surveillance and reservoir monitoring. Data Analytics enables to get most value out of the vast volume of data being generated. In order to extend the present limits of digital oil field envelope from operations monitoring, companies need to harness data analytics to identify patterns, trends, correlation, forecasting out of its vast petroleum data. This includes exception based surveillance, case based reasoning, and condition based monitoring in order to facilitate advanced monitoring, and to support tactical and strategic decision-making process.

To establish data analytics environment it requires systematic way of capturing, storing and managing data, integrating and embedding data analytics into the mainstream sub-surface, drilling, production and operations workflows which includes integrated reservoir monitoring, drilling and production optimization. Data analytics technology blends traditional data analysis with sophisticated algorithms and business rules for processing large volumes of diverse types through an Integrated Data Analytics Environment (IDE). Data governance is a vital part of IDE to ensure there is clear ownership and responsibilities as the accuracy of the results are as good as the quality of the data. IDE environment enables systematic harvesting of operational event, lessons learnt and best practices to enable knowledge based operations decisions.

The integrated data analytics platform enables integrating E&P workflows and data analytics to enhance operations monitoring, predict well productivity, identify performance patterns and KPI, improve reservoir recovery factor, and predict equipment failure, towards achieving the objective of continuous optimization of oilfield performance.
Enhanced Oil Recovery by Combined Nanofluid and Low Salinity Water Flooding in Multi-Layer Heterogeneous Reservoirs
Authors: Yuan Bin , Moghanloo Rouzbeh Ghanbarnezhad , Zheng Da
Published: September 2016

The aim of this paper is to investigate an application of nanofluid-slug preflush to enhance well injectivity while improving the sweep efficiency by fines migration-assisted mobility control in multi-layer heterogeneous reservoirs during low salinity water flooding. An axisymmetric radial flow model and fraction flow analysis are applied to interpret the performance of nanofluid-slug and the following low salinity water injection in a layered heterogeneous flow system. The interplay among nanoparticles, fines and rocks is described by a physical-chemical reaction model. The improvement of mobility control is characterized as the ratio of displacement fronts' advancing velocity along each layer. The improved well injectivity by nanofluid preflush is presented as an explicit formulation of injectivity index. This paper also introduces a graphic workflow to optimize nanofluid treatment and injected water salinity for nanofluid-fines-assisted low salinity water flooding under arbitrary initial and injection conditions.

The results indicate: 1) Compared with conventional water flooding, the alteration of water salinity can help to achieve uniform water flooding profile within each heterogeneous layer and then improve sweep efficiency before water breakthrough; 2) The nanofluid preflush prior to water injection can effectively control fines migration in the vicinity of injection wells to improve well injectivity, but it cannot control fines migration in reservoirs that realizes mobility control by decreasing water-phase permeability in the higher permeable layers; and 3) there does exist an optimal nanofluid concentration and slug size to offset decline of permeability near wells and then improve water injectivity.

The outcomes of analytical model are validated by both numerical simulations. This paper has the following novel points: 1) the model provides physical insights to examine nanofluid utilization to improve well injectivity and enhance oil recovery; 2) The induced mobility-control by fines migration during low salinity water flooding is confirmed as an effective method to improve sweep efficiency in heterogeneous reservoirs.
Engineering Gravel Packs for Reliability
Authors: Wassouf Philip , Jain Samyak , Kranenburg Aart van
Published: September 2016

Sand production is a global problem which causes millions of dollars in equipment damage, deferred or lost production and non-productive time (NPT) every year. Consequently, the accurate selection, modeling and evaluation of sand control techniques is crucial for completion and production optimization as well as risk minimization. This has traditionally been done using spreadsheets, industry rules of thumb and previous experience but, as completions become more complex with longer intervals and smaller fracture pressure windows, error margins are tightening and the cost of failure increasing so a more robust approach is required.

This paper details the application of a novel commercially available gravel pack software in the prediction of circulating pressures and gravel placement during the wellbore displacement, step rate test and gravel pack stages of completions operations for two horizontal open hole wells completed with alpha/beta gravel packs. Each well is first simulated to predict expected packing and pressure trends, then evaluated using measured surface and downhole gauge data to identify actual packing mechanisms and better understand downhole events, and finally optimized by directly comparing predicted and measured data to validate model accuracy and reliability. This detailed approach enables the early identification and mitigation of potential risks as well as the ability to better investigate any failures for continuous improvements in both design and operations.

Overall, the model is found to match closely with measured data, providing a robust engineering tool for the simulation, evaluation and optimization of horizontal open hole gravel pack (OHGP) completions. The methodology presented facilitates the more accurate design of increasingly complex treatments and helps identify deviations from expected pressure and packing trends to reduce risk, improve reliability and maximize the likelihood of success.
Production Performance Modeling of Shale Gas Wells with Non-Uniform Fractures Based on Production Logging
Authors: Pang Wei , Du Juan , Zhang Tongyi , Mao Jun , Di Dejia
Published: September 2016

China is the first country achieving shale gas breakthrough outside the North America. Fuling shale gas play is one of the most successful shale gas reservoirs by far in China. However, production loggings in more than ten wells illustrate that only about one third to one half of hydraulic fractures produces. Meanwhile, the productive fractures contribute differently to the production rate. Therefore, models with non-uniform fracture properties like fracture half-length and distance between fractures are needed to model the production performance considering the production logging information.

In this paper, Models with non-uniform fracture properties are built to take into the consideration of production logging results. In these models, the fractures can be with un-even distance, un-even half-length while combing specific flowing features of shale gas play like desorption, diffusion and stress dependent permeability. Production logging operations of one case well in Fuling shale gas play are reviewed. In order to honor the production logging results, Interpretation models with non-uniform facture and the ones with uniform fractures are compared. Rate and pressure transient data are used to interprete the formation permeability, fracture half-length and stimulated reservoir volume (SRV) by rate normalized pressure (RNP) method. On the basis of understanding of formation properties from rate and pressure transient analysis and non-uniform fractures properties from production logging, production rate and estimated ultimate recovery (EUR) are predicted by the models with non-uniform fractures for the case well.

Results show that only about one third to one half of hydraulic fractures produces and the productive fractures have different contribution to total production rate of shale gas wells. Rate and pressure transient analysis with non-uniform fractures model gets higher formation permeability than the one with uniform fractures model. However, the fractures may have more severe interference between fractures in the non-uniform model and weaken the positive effect of higher permeability on shale gas well's production, or the dominant fractures may affect the less productive fractures adversely. Field applications show that the wells with non-uniform fractures will achieve about 21 percent less EUR than the one with equivalent uniform fractures.

Production performance modeling for shale gas wells with non-uniform factures obtained from production logging is the highlight. The research may partly help the design of horizontal laterals and fractures scenarios.
Reducing Drilling Risks in ERD Wells Through Geomechanical Solutions
Authors: Kaushik Y. D. , Baishya R. C. , Majithia P. P. , Bagchi D. , Pratap Mahendra , Kumar Rajeev , Kumar Devendra , Rao Dhiresh Govind , Singh Hemant
Published: September 2016

In the quest to achieve higher production, extended reach drilling (ERD) wells are planned to be drilled in the Bassein cluster, offshore India, threatened by high risk of wellbore stability after severe hole problems drilling low-angle exploration and appraisal wells. The key to successful drilling is to predict optimal mud weight windows for safe and stable ERD wells with a casing plan to drill the critical buildup section from 30° to 75° through overlying shales. The in-situ stress profile is built and further calibrated with closure pressures obtained during extended leakoff tests and stress testing with the modular formation dynamics tester. Rock mechanical properties are estimated to history match actual failures with predicted failures using the geomechanical model and mud weight used while drilling.

Reported cavings and stuck tool incidents in shale formations are at depth intervals where the estimated breakout mud limit exceeds the mud weight used during drilling of offset wells. There is variation of rock elastic properties like Young's modulus and Poisson's ratio with direction in shale. Intermediate lower-strength coal and shale layers are seen in the Panna sandstone against overgauged hole condition observed in offset wells. Stable mud weights to avoid breakouts are in range of 11.6 to 12.5 ppg depending on well azimuth and deviation across different shale layers. Variations in minimum stable mud weight are in the range of 0.3 to 0.5 ppg based on well azimuth with reference to minimum horizontal stress direction from same platform. Even with depletion of 1.2 ppg in hydrostatic limestone, the minimum mud weight required to safely drill the horizontal section is 8.7 to 8.9 ppg due to lower- strength layers. Well deviation should remain same in the 12.25-in. section to avoid hole cleaning issues in shale. The breakout-mud loss window varies between 1.3 and 1.8 ppg at high well deviation in the 12.25-in. section. The 20-in. casing shoe plan was modified by setting deeper by 100 to 150 m to obtain a higher mud weight window. Lower core recovery at the top of the target limestone reservoir coincides with overgauged hole conditions seen across all offset wells. The local normal fault regime identified against regional strike-slip geological setting.

The modifications resulted in significant reduction of nonproductive time with no lost-in-hole incidents and time savings of 1 week on each ERD well compared to offset wells. The good hole condition made it possible to acquire formation pressure measurements across the field to update the reservoir model and understand the structural connectivity of different target layers.
Flow Assurance During Deepwater Gas Well Testing: When and Where Hydrate Blockage Would Occur
Authors: Zhao Yang , Wang Zhiyuan , Zhang Jianbo , Wang Xuerui , Sun Baojiang
Published: September 2016

The current dominant method to handle hydrate associated problems during deepwater gas well testing is injecting massive inhibitors (e.g. methanol and glycol). This technique is uneconomical and environmentally harmful. A model is established to assess when and where a hydrate blockage would occur in the testing tubing. The characteristics of gas hydrate formation and deposition in the testing tubing are analyzed based on recent published gas-dominated flowloop investigations. The growth of the hydrate film formed on testing tubing walls is modeled. The model is used to estimate the amount of hydrates formed (on the tubing walls) and determine when and where hydrate blockage would occur. Based on the proposed model, a case study is carried out to investigate the effect of gas production rate, water depth, and inhibitor concentration on hydrate blockage development during deepwater gas well testing operations. Hydrates form and deposit more rapidly and the growth rate of the hydrate layer is higher when the gas production rate decreases, and/or the water content and the water depth increase, thus it takes a shorter time for hydrates to block the testing tubing. Conversely, longer time is required for the formation of hydrate blockage. For a typical deepwater gas well (water depth: 1565 m, liquid holdup: 3 %, gas production rate: 45×104 m3/d), it takes about 35 hours for the occurrence of hydrate blockage. Injection of hydrate inhibitors significantly delays the blockage. The study suggests that no inhibitors are required when the well testing operation can be completed before hydrate blockage occurs. Otherwise, the hydrate risk can be managed by injecting small amounts of inhibitors to delay the blockage, rather than keeping the system totally out of hydrate stability region with a high inhibitor fraction. The study suggests a more economical and environmentally friendly hydrate management technique for deepwater gas well testing operations, which can be applied as an alternative to the current total prevention method. The proposed model can be used as a useful tool for flow assurance engineers to estimate hydrate blockage risk and optimize inhibitor injection.
A Shale Matrix Imbibition Model – Interplay between Capillary Pressure and Osmotic Pressure
Authors: Li Xiaopeng , Abass Hazim , Teklu Tadesse W. , Cui Qi
Published: September 2016

High and efficient deliverability of stimulated reservoir volume through a hydraulic fracturing treatment relies on three segments: fluid flow from matrix to the interface between fracture and matrix media, fluid-rock interaction at the fracture-matrix interface, and conductivity of fracture network. Thus, fluids and salt exchange between matrix and fracture network are critical and worth detailed investigation. Moreover, matrix imbibition as an important EOR mechanism has been extensively studied but the focus was mostly given to capillary effect. However, for shale, due to the pore structure and clay content, some physico- or electro-chemical forces at molecular level cannot be overlooked anymore, such as osmosis.

A multi-mechanistic numerical shale matrix imbibition model is developed. The model takes into account dynamic water movement caused by capillary pressure and osmotic pressure as a function of water saturation and salt concentration, respectively. The rock matrix is considered as the mixture of two different components, one with small nano/micro-pores and semi-permeable membrane property and the other having larger meso-pores. The model properly simulates water and salt transportation occurring across the matrix-fracture network contact surface driven by capillarity, osmosis, and salt diffusion. To honor the physics, the salt/ions concentration equation differs from previous work by removing the osmosis component and a new membrane efficiency coefficient is defined and properly incorporated in the model.

Spontaneous imbibition test results were used for matching and validation purposes. The simulation results well explained laboratory high-salinity water imbibition curve, which can be divided into three processes. Initially, a capillary driven imbibition sucks high salt-concentration water into matrix near the matrix-fracture contact surface. However, due to the significant salinity contrast between imbibed fluids and in-situ matrix salinity, a drainage process can be induced. Eventually, as salinity difference decreases and osmosis is weakening, final imbibition stage starts. This model provides a basis for laboratory measurements interpretation and brings some insights to reveal the underlying mechanisms for field post-frac flow-back behavior.
A Robot that Removes Operators from Extreme Environments
Authors: Peerless Ian , Serblowski Adam , Mulder Berry
Published: September 2016

Hydrocarbon exploration and production is moving into increasingly extreme environments as exemplified by the Kashagan field in Kazakhstan. This has high concentrations of high pressure hydrogen sulphide gas, extreme climactic variations, and remote normally unmanned islands that can be difficult to access at certain times of the year. Therefore, the North Caspian Operating Company (NCOC) decided to investigate whether its production operators could work from the safety and comfort of the control room while operating on-site robots.

Sensabot evolved from this challenge. It is characterised by its ability to operate in potentially explosive environments, long intervals between routine maintenance, and the fact that it can operate in walkways that have already been designed for human access.

The Sensabot project was launched in 2010 and has been led by Shell on NCOC's behalf. The Mark 1 Sensabot was delivered in 2011 and contained an array of cameras, gas detectors, a vibration detector and a microphone. Trials of this robot were very successful so the development project was continued resulting in a manipulation arm and Sensabot Mark 2. The latter is now proceeding through the certification process for Zone 1 explosive environments with a view to deployment in Kazakhstan during 2016.

Leaders of upstream oil and gas companies will benefit from an understanding of Sensabot's capabilities and of the implications for improved operational safety. There are also early indications that robots might improve operational efficiency in extreme environments.
Monitoring of Matrix Acidizing by Using Resistivity Measurements
Authors: Ghommem Mehdi , Qiu Xiangdong , Brady Dominic , Al-Tajar Firas , Crary Steve , Mahjoub Alaa
Published: September 2016

This paper is focused around testing a novel concept based on resistivity measurements to monitor acid stimulation operations. A feasibility study was carried out to show the potential success of the proposed concept. A series of coreflooding experiments were conducted at elevated pressure (3,000 psi) and high temperature (65°C) while recording the resistivity and pressure data from taps placed along a rubber sleeve housing the core samples. Results show the ability of the resistivity measurements to track the acid penetration and provide insight on the wormhole morphology. A numerical model was also derived to determine the electrical resistivity while injecting acid and dissolving the rock sample. A comparative study with the experimental results shows that the model predicts the change in the electrical resistivity during acid injection with good accuracy.

It is believed that the proposed concept for monitoring the wormholing process can be adopted in the field with the deployment of the induction tools. A yard test was performed to verify the response of a real induction tool to simulated wormholing features. The results demonstrate the capability of the resistivity measurements to delineate the wormholing zones. The outcome of this novel monitoring concept is expected to provide an unprecedented level of understanding of the depth, the number, and the type of wormholes being created downhole. The interpretation of the wormhole formation and propagation will provide guidance to enhance the operational efficiency and maximize productivity gains along the entire wellbore.