bluuebunny/crossref_metadata_2025 huggingface dataset:
Successfully Drilling an Extremely Complex ERD, HPHT Exploration Well
Authors: Alemi Hassan , Uzu Ugo , Pourtangestani Mehdi , My Lien Ta , Maliekkal Harish
Published: October 2018

To meet the ever-growing demand for oil and gas, operators today are forced to search for reservoirs in more challenging environments characterized as high-pressure high-temperature HPHT using extended-reach drilling (ERD) techniques. A major operator in the Central North Sea successfully drilled a complex extended-reach drilling (ERD), HPHT exploration-production well in the central North Sea presented numerous challenges, This well contains one of the largest outstep HPHT wellbore ever drilled, and contains one of world's heaviest production casing strings. The HPHT environment causes various drilling problems, such as accelerated thickening of drilling fluids, reduction in rate of penetration (ROP), lost circulation, swabbing during pulling out the string, stuck pipe, and hardware failure. The complex nature of this ERD well created specific problems, including torque and drag, hole cleaning, casing running, equivalent circulating density management, and wellbore stability. The operator planned to drill this HPHT exploration and production well by sidetracking from an existing well. In addition to the HPHT and ERD challenges, other drilling challenges consisted of hard rock, high-pressure reservoir, differential sticking risk, a one-way casing/liner run, potentially depleted sands, and possible severe casing wear. These numerous and varied challenges required quick operation decisions to avoid costly overruns.

This paper presents the method used by the operator to successfully drill and complete this complex ERD, HPHT well access a reservoir containing several challenging drilling conditions and potential obstacles to achieving the well objectives. The successful operation demonstrates the importance detailed engineering, communications, and an integrated effort played in successfully delivering this challenging well.
Filter Cake Buildup in Horizontal Wells: Characterization and Impact on Removal Operation
Authors: Hamzaoui Bilel , Al Moajil Abdullah M. , Caliskan Sinan , Aldarweesh Sajjad S
Published: October 2018

The drilling fluid in a vertical well may only be in the pay zone for few hours while in a horizontal well the time can be measured in weeks. This can cause a significant formation damage problem that has the potential for reducing productivity in horizontal wells during drilling operations. A common practice following drilling operations involove filter cake removal operation followed by displacement of wellbore fluids by completion fluid in order to prepare the well for production operations. Presence of drilling fluids in horizontal wells for several weeks is not considered in the design for cleaning fluid recipies targeting drill-in fluid damage. The filter cake buildup time affect its physical characteristics and thus, on the removal process. This study focused on the characterization and the cleanout of the filter cake during the different buildup stages that may occur in the horizontal section. The focus of this study is to highlight the effects of not promptly removing the filter cake.

Filter press instrument was used to simulate filter cake formation on the wellbore wall at 500 psi and 300°F. The filter cake formation process was performed using oil-based drilling fluid at different buildup times (i.e., 3 hours, 3 days and 3 weeks), under 500 psi and 300°F.

The comparison of the different scenarios showed that a thicker filter cake was formed with buildup time (up to 2.5 inch after 21 days). The CT scan results showed that the heterogeneity increased up to 4 layers and the solubility of in the cleanout fluid decreased to 4% by weight.
Driving Efficiencies in Well Intervention Operations
Authors: Yong Yee Tzen , Azizan Yusri , Leong Azemi , Song Yan , Abd Rani Rudzaifi Adizamri
Published: October 2018

Brunei offshore platforms are home to hundreds of maturing wells in need of ongoing interventions. Offshore operations in Brunei face several obstacles, (i.e., weather conditions, ageing platform facilities, limited lifting capability, and limited workspace), as well as tight work schedules that make the work challenging.

As with other mature fields, the Brunei wells need high efficiency operations to reach production targets. These challenges can be addressed with a purpose built compact semi-submersible vessel (CSS) with dynamic positioning (DP 2) equipped with a full catenary coiled tubing unit, a pumping unit with flowback capability, and a dedicated slickline unit.

Dual hull design with a compensated gangway increases the weather working envelope of the vessel. The coiled tubing catenary system with a reel turntable helps enable coiled tubing unit flexibility during rigup and work under varying weather conditions. Integration of the vessel and the coiled tubing unit helps enable a 24/7, 365 day work unit.

Average downtime caused by weather decreased by up to 10%, averaging 8.5% in 2 years, compared to previous work vessels with an average between 15 and 18% downtime because of weather.

Further efficiency improvement is gained through use of fit for purpose equipment. A 35 ton jacking frame helps enable injector and pressure control equipment stack up to be made up, function, and pressure tested offline. A small footprint flowback package was introduced that reduced the total number of lifts from 12 to 6, saving two hours lifting time per rig up/down. Overall rigging up time was reduced by approximately 20% with the improvements to equipment setup.

The reduced equipment necessary on the platform enabled wireline and coiled tubing to operate concurrently. This enables 24 hour wireline interventions to be executed offline more efficiently. Time savings for intervention completion were approximately 62%. This setup enables more efficient use of existing resources to complete the work scope.

The setup, collaboration, and execution on the vessel demonstrate the opportunity for improvement, which is important under current industry conditions, and help enable a cost effective yet robust operation.
A Quantitative Approach to Forecast Well Productivity While Drilling
Authors: Li Maowen , Lei Guowen , Zhang Mingjie , Coskun Sefer B. , Sy Resksmey C. , Hardikar Nikhil P.
Published: October 2018

The WEIZHOU-XYZ project is a newly developed offshore oilfield located in South China Sea. A quick and accurate productivity estimate would add valuable information to the decision-making on further field development, which is divided into three phases as per priority. A luxury dataset comprising seismic, drilling, well logs, well testing and production was acquired from most wells drilled in Phase-1. The objective of this paper is to establish a fast productivity forecasting method that can be used for the newly drilled wells of Phase-2 and Phase-3 after acquiring logging-while-drilling (LWD) data only.

The well-productivity forecasting model was based on uncertainty analyses using the Monte-Carlo method. Starting with equations of the production rate and the productivity index, each parameter of the equations has been investigated based on LWD data, and with a reference to the Phase-1 wells. Two key reservoir data used for the forecasting model are LWD formation testing (formation pressure while drilling - FPWD) and LWD nuclear magnetic resonance (NMR). These two dataset are the main information collected while drilling along with LWD resistivity and gamma ray in Phase 2. The FPWD data provides mobility, thus indicating the ability of fluid flow through the permeable reservoirs. The LWD NMR data provide continuous porosity measurement. Additionally, the T2 relaxation sensitives to both the pore size distribution and fluid properties providing estimation of formation permeability and fluid viscosity. Differing from the conventional way of a constant value input to the production rate equation, the proposed method sets all productivity related parameters (permeability, thickness, formation volume factor, viscosity, drainage radius etc.) under an uncertainty distribution range. The productivity prediction model is processed and evaluated using Monte-Carlo simulations. A scenario of 10,000 runs were conducted to account for the possible production distribution. As a result, an expected value of production rate or productivity index is used for the delivery of the possible forecasting outcome.

In this study, a successful application of this forecasting model has been proven by a good match with actual results from a well test. The observed difference is less than 5% between the real production rate and the expected value from the forecasting model.

This paper shows that formation testing while drilling and NMR while drilling together provide valuable inputs for productivity forecasting. The integrated method would be very helpful and meaningful for the production evaluation and decision-making for the Phase-2 and Phase-3 development wells, which will have limited data acquisition. A Monte-Carlo simulation workflow has been proposed for quantitative prediction.
Step Change in BHA Reliability and Performance Due to Utilization of Downhole Drilling Dynamics Services
Authors: Reckmann Hanno , Hohl Andreas , Oueslati Hatem , Akimov Oleg
Published: October 2018

To reduce cost, drilling operations are getting longer, both in time and distance. Simultaneously, drilling parameters are optimized to reach higher performance for a maximum rate of penetration (ROP). The drawbacks of these practices are increased static and dynamic loads such as bending stresses, torque, and vibration on the drilling system. These parameters can greatly fatigue even the most robust drilling tools. Downhole drilling dynamics services must be used to ensure reliable operation with optimum performance.

This paper discusses the general challenge to balance reliability and performance. For this process, tools are needed to measure the respective downhole data. A database is required to help connect downhole dynamics data and surface data like drilling parameters such as weight on bit and rotary speed, with context data such as geological formation and system reliability. To analyze dependencies and optimization approaches, it is necessary to review the data in various ways and from different perspectives through the data sets. This review can be achieved by using crossplots in various dimensions.

The recording of downhole data with sampling rates exceeding 1000Hz and subsequent analysis of high-frequency drilling data provide insight into the excitation mechanism for vibrations. Additional statistical analysis of the data reveals the true load profile on the drilling system and its origin, enabling optimization in two ways. The tool or system design is optimized for reliability considering the identified loads, and the loads are minimized by optimizing the drilling parameters. Novel modeling techniques enable estimation of the dynamics load distribution over the bottomhole assembly (BHA), even from a single measurement position. Analysis shows that the main dynamic loads stressing the system are lateral vibrations and high-frequency torsional oscillations. Temperature effects also play a significant role for electronics. Statistical models support the decisions to retire tools or components and any re-run decision.

The use of drilling dynamics services and the real-time downhole data ensure informed decisions during the drilling process, optimized performance by minimizing loads on the system, and maximized ROP with optimal drilling parameters. The collected downhole data, in combination with context data and reliability data applied in the design process, lead to fit-for-purpose designs of the latest drilling tools.
Effect of Synthesized AMPS-g-Clay/CuO NanoComposite on WBDFS for Challenging Formations
Authors: Kumar Nitesh , Kumar Akaash , Kumar Saket
Published: October 2018

An attempt has been made in this work to formulate a novel water based mud system with acrylamido-methyl-propane sulfonate polymer (AMPS) grafted clay/CuO nanocomposite for drilling the high temperature troublesome shale formations. Literature survey found several water mud applications of AMPS polymers in the high temperature and high salinity environment as they are highly water-soluble anionic additives. On the other hand, investigators have reported very encouraging results on rheology and fluid loss control, shale impact, well bore stability and strengthening, cuttings lifting capacity and suspension and impact on thermal properties with CuO nano particle. The improvement in rheological and fluid loss control can be attributed to the fact that pore size studies on shales have suggested nano pore size of 2-50 nm. Conventional shale stabilizers and polymers contained in a water based mud cannot plug nanopores of shale. Therefore, water invades into the wellbore, and results in high mud filtrate volume and clay swelling. Given above, AMPS grafted clay/CuO nanocomposite is expected to improve on the CuO nano particle (NP) performance and provide an excellent solution to plug nano pore size of the shale. Hence, in this paper we tried to develop a synthesized additive which assists the drilling mud to provide better bore hole stability and well integrity while drilling the formations.
Optimizing Heavy Oilfield Development through Innovative Logging While Drilling and Horizontal Well Steam Stimulation with Multiple Fluids Technologies in Bohai Bay
Authors: Zhang Binqi , Liu Feng , Zhang Bo , Zuo Cunhai , Zhang Xiaowei , Yu Xiaoning , Wang Fei , Xu Tianyun , Wu Kai , Hu Zhong , Yuan Xiangwei
Published: October 2018

More than 70% reserve explored in Bohai Bay, northern offshore field in China, could be categorized as heavy oil. Only relying on the conventional production process leads to both low production rate and low recovery rate. Take NB-N oil field as an example, which started production in Oct-2005. As of April 2011, there are a total of 27 development wells, with a daily oil production of 174 m3, water cut up to 77%, and recovery rate 0.2%. The oil recovery rate is 1.52% OOIP (Original Oil in Place) only, which does not meet the expectations.

To optimize the heavy oil reservoirs production, a series of comprehensive studies and field test were carried out in the Bohai field. Innovative Logging While Drilling technology was deployed to provide distance to boundary (DTB) detection ability and combined with Rotary Steerable System (RSS) technology, which enables the wellbore to be close to target roof and maximizes reservoir exposure as the result. According to the reservoir characteristics, oil recovery technology of steam stimulation with multiple fluids (SMF) by injecting steam and non-condensate gas into oil reservoirs increases production rate. The injected gas not only enlarges the influencing scope for thermal production but also reduces viscosity together with the injected heat, thus lowering the requirements for thermal production, reducing heat loss and improving the economic feasibility of thermal production.

The paper will feature the best practices of utilizing the above innovative approaches to optimize horizontal well drilling and enhance the heavy oil reservoir performance. Several key outcomes have been observed in this project: Five horizontal wells were drilled with 100% NTG and lateral sections were place close to target top to minimize attic oilWith the SMF technology, the average single-well daily production was increased from 10-20 m3 to 50-60 m3 when cold production process was used. The effective production period lasted 300-400 days.

The successful application of innovative technologies in NB projects, has improved both oil production and recovery rate of this heavy oil reservoir. Ultimately, this has enabled the economic use of heavy oil reservoir, especially in the Bohai Bay. The author also believes this approach could be extended to the similar type reservoir as a fit-for-purpose solution.
A New Generation Environment Friendly Water-Based Drilling Fluid and Field Applications
Authors: Zhu Qi , Wang Yong , Zhang Yongqing , Sun Zhihe , Wei Yinghui , Wang Runping
Published: October 2018

Currently, synthetic additives are widely used in drilling fluid, but these additives have hazards, such as, toxicity, difficult to degradation, leakage and volatilization caused great influence to wellsite environment. Environmentally friendly drilling fluid has been appeared around for decade. However, because of high cost of raw materials, lack of adequate supplement and complexity of modified synthetic process, there has been no widespread industrial application in China. The majority of test wells are straight, but deviated well and highly-deviated well test is seldom reported.

A series of indoor evaluation and field applications were carried out in process of modifying low cost additives to the environmentally friendly treatment agents. HTHP aging and filtration experiment to verify temperature resistance; adding sodium chloride to verify anti-salt properties; adding bentonite and cuttings recycling experiment to verify inhibition performance of slurry and mud shale; friction resistance experiment verifies that lubrication capacity meets deviated well and highly-deviated well operations; core flow experiment to verify reservoir protection performance; heavy metal, biochemical oxygen demand, chemical oxygen demand, biological toxicity analysis experiment to verify influence of the system on environment.

Ability of temperature resist 120 °C, anti-salt ability reaches saturation and recovery of cuttings is more than 85%. Environmental performance of the drilling fluid system is ideal, EC50 value is 1.61×105, no biological toxicity, BOD5/CODcr is 0.11, easy biodegradation. Field application for morethan 30 wells, with beyond 20 deviated wells and highly-deviation angle more than 50 ° wells are 10.

The new types downhole tools for speeding-up and controlling hole size, rotary impactor and wellbore cleaner, were used to improve mechanical penetration rate (ROP) and wellbore cleaning. After employing the environment system, the drilling fluid does not need to be transshipped and processed directly in wellsite, and well fields are restored. Drilling fluid disposal process saves the cost of artificial working, transportation and environmental management. This drilling fluid system is first applied on-site in North China, which fills the blanks and provids reliable technical support and reference examples for the subsequent replacement of drilling fluid systems used now in North China.
Alkaline/Surfactant/Polymer Flooding With Sodium Hydroxide in Indiana Limestone: Analysis of Water/Rock Interactions and Surfactant Adsorption
Authors: Tagavifar M.. , Sharma H.. , Wang D.. , Jang S. H. , Pope G. A.
Published: October 2018

We recently used sodium hydroxide (NaOH) in Indiana limestone coreflood experiments to lower anionic-surfactant adsorption. This study presents analysis of the limestone geochemistry and the surfactant adsorption under static and dynamic conditions. Analysis of the effluent ionic composition using ion chromatography and inductively coupled plasma showed the presence of sulfate (SO42−) aluminum (Al), and iron (Fe), as well as calcium (Ca) and magnesium (Mg). To determine the likely source of each geochemical species and to characterize how the dissolution kinetics changes the slug chemistry, PHREEQC was used to inverse-model Indiana limestone rock using the bulk X-ray-diffraction (XRD) mineralogical composition and the influent and effluent water chemistry. Results showed that all Indiana limestone cores contained anhydrite, which was not detected by XRD. The effluent concentration of Al increased with pH to approximately 15 mg/L, whereas Fe concentration remained fairly independent of pH at 0.04 ± 0.02 mg/L. These trends suggest the likely source of Al and Fe to be either clay dissolution or the release of natural clay colloids with NaOH. Simulations suggested that in Fe-bearing carbonates, alkali consumption is fast but limited with NaOH, which is observed as pH-front delay, whereas alkali consumption is slow but severe with sodium carbonate (Na2CO3) resulting in minimal pH-front delay but lower effluent pH compared with influent pH for prolonged injection times. Using the PHREEQC calculations, the ionic composition of the chemical slug in subsequent alkali/surfactant/polymer (ASP) experiments was adjusted. In addition, the coupled adsorption/transport of anionic surfactants in carbonate rocks was also investigated using surface-complexation-model adsorption under static and dynamic conditions. Model predictions agree with the single-phase-adsorption coreflood results and suggest that the adsorption on the metal oxides or clay could be comparable with that on calcite. This arises from the higher surface area and the point of zero charge of pH (pHpzc) of metal oxides.
Surface-Charge Alteration at the Carbonate/Brine Interface During Single-Well Chemical-Tracer Tests: Surface-Complexation Model
Authors: Khaledialidusti Rasoul , Kleppe Jon
Published: October 2018

Water chemistry has been shown to affect oil recovery by affecting surface charge and rock dissolution. The single-well chemical-tracer (SWCT) test is a field method to measure residual oil saturation (Sor), in which hydrolysis reaction of an ester has been known as a key process that could displace the equilibrium state of a reservoir by changing formation-water (FW) composition.

Because oil mobilization during the SWCT tests causes an error in the measurement of Sor, changes in water chemistry might be a concern for the accuracy of Sor measurements. In our previous work, the extent to which different reservoir parameters might change water composition and the effect of water-chemistry changes on the calcite dissolution and the oil liberation from the carbonate-rock surfaces were extensively evaluated. In this study, the effect of water-chemistry changes on surface-charge alteration at the carbonate/brine interface has been studied by constructing and applying a surface-complexation model (SCM) that couples bulk aqueous and surface chemistry. We present how the pH drop induced by the displacement of the equilibrium state and changes in water chemistry in the formation affect surface charge in a pure-calcite carbonate rock during the SWCT tests.

The results show that a pH drop during the SWCT tests while calcium concentration is held constant in the FW by ignoring calcite dissolution yields a less-positive/more-negative surface charge so that wettability of carbonate rock might be altered to a less-oil-wetting state, when the oil is negatively charged. In reality, however, calcite dissolves by water-chemistry changes during the SWCT tests, which leads to an increasing calcium concentration in the FW. Consequently, an SWCT test in carbonates is accompanied by increasing calcium concentration while pH drops, which yields an increase in the surface charge of carbonate rocks. Therefore, the pH drop does not directly affect the surface charge of carbonate rock during an SWCT test, and calcium concentration increased from calcite dissolution could control the surface charge more significantly.
Numerical Simulation of Supercritical-Water Flow in Concentric-Dual-Tubing Wells
Authors: Sun Fengrui , Yao Yuedong , Li Guozhen , Li Xiangfang
Published: October 2018

Much work has been performed on the modeling of saturated/superheated-steam flow in wellbores. At present, the study on supercritical-water (SCW) flow in wellbores, especially concentric-dual-tubing wells (CDTWs), is very limited.

In this paper, work was performed on modeling of SCW flow in CDTWs. First, a comprehensive mathematical model comprising a pipe-flow model, supercritical-fluid model, and heat-transfer model is established. In the model, the heat exchange between the integral joint tubing (IJT) and annuli is taken into consideration. Numerical solutions of SCW flow in CDTWs were obtained with a straightforward numerical method. Then, sensitivity analysis was conducted. The following results were found:

SCW in annuli (with a higher temperature) releases thermal energy to SCW in the IJT, which causes increase of temperature in IJT. As a result, SCW density in the IJT has a decrease. The density gradient near the wellhead increases with increasing of injection rate. When the injection temperature in the IJT is larger than that in annuli, SCW density increases with well depth near the wellhead.
Buildup-Pressure Extrapolation of a Heterogeneous Reservoir: Application of the Crump and Hite Method to a Real Field Case
Authors: Piccinini R. B.
Published: October 2018

Traditional methods of pressure-transient analysis rely on homogeneous reservoir models and require assumptions on reservoir shape and well-flow regimes. Unsteady flow rates offer further complexity because traditional methods are dependent on past production history. Crump and Hite (2008) proposed a new method for estimating average reservoir pressure that applies to heterogeneous reservoirs and only requires knowledge of the pressure-buildup data. The Crump and Hite (2008) method relies on obtaining the first few eigenvalues of a diffusion equation to predict average reservoir pressure. A large buildup time may be required for a successful application of the method, depending on the magnitude of the first eigenvalue.

This work applied the Crump and Hite (2008) method to a real field case. A reservoir was produced by a single horizontal well for a period of a few years, which was followed by a shut-in period of approximately 200 days. The first four eigenvalues could be extracted, providing an estimate of average reservoir pressure. The pressure derivative was computed with a total-variation-regularization method, which showed lower noise levels compared with finite-difference methods. The extended version of the Crump and Hite (2008) method for shorter buildup times did not show a substantial reduction of the buildup-time requirement.
Long-Period, Long-Duration Seismic Events and Their Probable Role in Reservoir Stimulation and Stage Productivity
Authors: Kumar Abhash , Zorn Erich , Hammack Richard , Harbert William
Published: October 2018

Hydraulic fracturing is a well-established technique to extract gas or liquid hydrocarbons from low-permeability formations such as shale and tight gas reservoirs. Diffusion of hydrofracturing fluid outward from the stimulated fractures into the target formation produces slip across pre-existing fractures and other discontinuities in the rock. Microseismic events recorded by downhole seismic-monitoring arrays are a manifestation of associated deformation. Recent investigations suggest that the total cumulative seismic moment of microearthquakes during hydraulic fracturing is only a small portion of the total seismic-energy release expected for the fluid volume injected into the formation. These observations suggest that other sources of energy release (such as inelastic deformation), contemporaneous with microseismicity, should be considered relevant to the hydraulic-fracturing process. Recent observations on long-period, long-duration (LPLD) seismic events suggest that slow slip emission along weaknesses that are misaligned with respect to the present-day stress field is likely an important mechanism of deformation and should be better understood and quantified in reservoir stimulations. In Morgantown, West Virginia, we conducted seismic monitoring of hydraulic-fracturing activity using an array of five broadband, three-component (3C) surface seismometers. Using this network, we identified 89 high-amplitude, impulsive events and 436 LPLD events, with highly emergent waveform characteristics. In these interpreted LPLD events, we observed a significant concentration of energy in the 0.8- to 3-Hz frequency range. During hydraulic fracturing, LPLD events were found to occur most frequently when the pumping pressure and rate were at or near maximum values. Because the main purpose of hydraulic fracturing is to stimulate oil and gas production from the less-permeable reservoir, we compared the relative production contributions/stage to the frequency of the occurrence of suspected LPLD events. We found a positive correlation between the frequency of LPLD events and stage-by-stage gas production, highlighting the potential contribution of slow deformation processes and its effectiveness in the reservoir stimulation.
Robust Life-Cycle Production Optimization With a Support-Vector-Regression Proxy
Authors: Guo Zhenyu , Reynolds Albert C.
Published: October 2018

We design a new and general work flow for efficient estimation of the optimal well controls for the robust production-optimization problem using support-vector regression (SVR), where the cost function is the net present value (NPV). Given a set of simulation results, an SVR model is built as a proxy to approximate a reservoir-simulation model, and then the estimated optimal controls are found by maximizing NPV using the SVR proxy as the forward model. The gradient of the SVR model can be computed analytically so the steepest-ascent algorithm can easily and efficiently be applied to maximize NPV. Then, the well-control optimization is performed using an SVR model as the forward model with a steepest-ascent algorithm. To the best of our knowledge, this is the first SVR application to the optimal well-control problem. We provide insight and information on proper training of the SVR proxy for life-cycle production optimization. In particular, we develop and implement a new iterative-sampling-refinement algorithm that is designed specifically to promote the accuracy of the SVR model for robust production optimization. One key observation that is important for reservoir optimization is that SVR produces a high-fidelity model near an optimal point, but at points far away, we only need SVR to produce reasonable approximations of the predicting output from the reservoir-simulation model. Because running an SVR model is computationally more efficient than running a full-scale reservoir-simulation model, the large computational cost spent on multiple forward-reservoir-simulation runs for robust optimization is significantly reduced by applying the proposed method. We compare the performance of the proposed method using the SVR runs with the popular stochastic simplex approximate gradient (StoSAG) and reservoir-simulations runs for three synthetic examples, including one field-scale example. We also compare the optimization performance of our proposed method with that obtained from a linear-response-surface model and multiple SVR proxies that are built for each of the geological models.
Three-Phase Relative Permeability and Capillary Pressure Models With Hysteresis and Compositional Consistency
Authors: Neshat Sajjad S. , Pope Gary A.
Published: October 2018

New coupled three-phase hysteretic relative permeability and capillary pressure models have been developed and tested for use in compositional reservoir simulators. The new formulation incorporates hysteresis and compositional consistency for both capillary pressure and relative permeability. This approach is completely unaffected by phase flipping and misidentification, which commonly occur in compositional simulations. Instead of using phase labels (gas/oil/solvent/aqueous) to define hysteretic relative permeability and capillary pressure parameters, the parameters are continuously interpolated between reference values using the Gibbs free energy (GFE) of each phase at each timestep. Models that are independent of phase labels have many advantages in terms of both numerical stability and physical consistency. The models integrate and unify relevant physical parameters, including hysteresis and trapping number, into one rigorous algorithm with a minimum number of parameters for application in numerical reservoir simulators. The robustness of the new models is demonstrated with simulations of the miscible water-alternating-gas (WAG) process and solvent stimulation to remove condensate and/or water blocks in both conventional and unconventional formations.
A Dynamic Model with Friction for Comprehensive Tubular Stress Analysis
Authors: Mitchell Robert F. , McSpadden Albert R. , Goodman Malcolm. A. , Trevisan Ruggero , Watts Rick D. , Zwarich Nola R.
Published: October 2018

A new model technique is described for comprehensive dynamic stress and displacement analysis of wellbore tubulars including friction loads. A dynamic model of tubing forces is necessary to predict local pipe velocity which in turn determines the magnitude and direction of localized frictional contact. By tracking dynamic changes in axial force starting from the initial running state, a complete load history may be simulated through the life of the well.

The dynamic friction model subdivides the string joint by joint and uses an elastic pipe momentum balance. Pipe velocity is related to axial force by the elasticity equation. Dynamically determined velocity is necessary to predict magnitude and orientation of local node friction vectors. Damping for the dynamic analysis is provided by annular fluid viscosity. The elastic equations are solved as a set of algebraic equations in terms of past and future values of pipe axial force and velocity. Key model inputs such as pressure, temperature, fluid and wellbore friction coefficients can be changed at each successive load step.

Running loads and packer setting with slack-off or pick-up loads determine the initial string configuration. Given the initial configuration, each subsequent load case is calculated starting from the prior load and resultant friction state, allowing for full history dependence. The surface velocity profile of running individual stands is a key input. Unexpected magnitudes of downhole transfer of surface load are demonstrated. Change in operation load sequence is shown to produce significant differences in tubular axial loads, indicating that special attention to load history should be considered when performing tubular stress analysis. For slack-off, overpull, or packer setting events the model can track dynamic load response at downhole points such as a packer or cement top. An example well with deviated profile and planned sequence of life-cycle operations including stimulation, production and shut-in was simulated for a variety of load sequences. The model has been validated against field data using the actual hook load plot during installation of a single-trip, multi-zone intelligent completion in an offshore highly-deviated ERD well. Example calculations are given for an HPHT subsea well and a horizontal unconventional well.

The dynamic friction model allows for seamless integration of running loads with friction into a fully sequential stress analysis of subsequent well life-cycle loads for landed strings. Current industry models separate installation state from the in-service life envelope. From comparison with appropriate static analytic solutions and industry standard drag and stress models, dynamics were found to affect friction force directions and magnitudes, suggesting that tubular dynamics cannot be neglected.
Accessing New Pay Intervals in the Tubing-Casing Annulus Above Top Packer with Cement Packer Technology, S Field, Peninsular Malaysia
Authors: M. Johan M. Alham , Al Zayani Sirag , Moritz Arthur Lee , Taylor Charles , Wibisono Rahmat , M. Mokhtar Shahril R. , Thian Kelvin , Samvelova Marina
Published: October 2018

As a low-cost alternative to expensive rig workovers, placement of a cement packer between tubing and casing has been previously applied in Malaysia. The purpose is to create a new annular barrier above the existing production packer to gain access to behind-casing opportunities (BCOs) or pay zones, removing the need for a workover. These pay zones, usually with minor or unknown production potential, have been left by the operator during initial completion because there were larger pay zones in deeper reservoirs. Cement packer placement can be achieved using basic intervention equipment as opposed to more expensive workover units.

The cement packer technique eliminates the need of recompleting the well with a conventional workover rig and reduces operational complications together with cost. There are different methods to deploy a cement packer. The highest chance of success, particularly when larger volumes of cement are needed, is using coiled tubing (CT) as the primary method to place the cement slurry in the tubing/casing annulus. In this method, a cement retainer was used and conveyed with CT. CT provides the ability to sting into the retainer and cement being displaced through the coil, ensuring all completion accessories have no contact with cement slurry which can impair their functionality, and also prevents U-tube effect of the slurry once cement is placed behind the tubing. After the cement is set, a cement bond log (CBL) is run to confirm cement integrity behind the completion tubing before adding new perforations.

This paper presents the successful cement packer placement operation with the help of the CT executed on an offshore platform in Peninsular Malaysia. A potential pay zone of the I-Group reservoir was discovered in the field after running pulsed-neutron cased-hole saturation logging tools, which are situated above the production packer; appraisal was required because of the unknown fluid type. Close collaboration among various parties in candidate selection, job preparation and design, cement laboratory testing, and operational planning and execution, were keys to the success of this pilot operation. By proving operational feasibility and economics, the technique opened up additional opportunities in restoring idle wells with bypassed reserves within the same field.
Julia Case History of the Stimulation and Lower Completion to Meet the 10kpsi Drawdown Tertiary Challenge
Authors: Amoruso James D. , Templeton-Barrett Elizabeth , Hecker Michael T. , Corbell Clifford A. , Kao Gilbert , Clayton Erik H. , Hixon James D. , Garzon Jorge L.
Published: October 2018

The Lower Tertiary Wilcox Julia field is a large resource with low permeability (average 10 mD) and 20 cP in-situ viscosity oil. In order to achieve optimum production rates and ultimate recovery, ultra-high 10,000 psi drawdown is required from a multi-zone fracture stimulated lower completion. This paper will review design and execution details of the 4-well Phase 1 lower completion and fracture stimulation design. Results from Phase 1 will be used in future reservoir studies to determine the ultimate development plan for the Julia Field.

The Julia reservoir and geology were studied and a single well simulation model developed to determine the optimal fracture geometries required to deliver low skin completions. A "clean sheet of paper" approach was taken to brainstorm all possible completion options to achieve these fracture geometries. Further study concluded a multi-zone fractured completion was needed to cover the typical ~2000ft vertical gross pay with 4-5 zones. The fracture gel, proppant and fracture designs were then developed to meet the fracture length and conductivity requirements. Four wells were completed with excellent results yielding initial skins of −4 to −6 when skins of −2 to −3 were expected.

Four multi-zone, ultra-deep (~31000'+ TVD), ultra high reservoir pressure (~21000-22,000 psi) wells were completed successfully with initial production rates better than expected on a per well basis The completions were executed without sticking a frac tool and without loss or abandonment of any zones. Each aspect of the completion, multi-zone, fractures, proppant, fracture design and implementation was key in achieving the ability to drawdown the wells up to 10,000 psi and optimize the Julia production for Phase 1. This development shows the team's approach across multiple disciplines of geology, reservoir, and sub-surface to meet the Lower Tertiary challenge. Results from Phase 1 will allow further reservoir studies to be conducted over the next several years to determine the best ultimate development plan for Julia. Well operability limits to define the allowable drawdown and depletion were calculated. Initial production curves with drawdowns are shown.
Production Forecasting for Shale Gas Reservoirs with Nanopores and Complex Fracture Geometries Using An Innovative Non-Intrusive EDFM Method
Authors: Yu Wei , Wu Kan , Liu Malin , Sepehrnoori Kamy , Miao Jijun
Published: October 2018

A rigorous and efficient numerical method for simulation of shale gas production considering complex hydraulic and natural fracture geometries and multiple gas transport mechanisms in nanopores is very important to evaluate stimulation effectiveness. In this study, we present an innovative EDFM (Embedded Discrete Fracture Model) method in conjunction with the third-party compositional reservoir simulator to simulate shale gas production considering all these complexities. Through the EDFM method, complex hydraulic and natural fractures can be directly and explicitly embedded in the matrix blocks. The complex fracture geometries can easily be handled without using local grid refinement near fractures or using unstructured gridding technique. In addition, gas transport mechanisms such as non-Darcy flow, gas desorption, gas slippage and pressure-dependent matrix permeability and fracture conductivity are included in the model. The LBM (lattice Boltzmann method) was used to model gas slippage phenomenon in nanopores. We verified the EDFM method against the LGR (local grid refinement) method for dealing with simple bi-wing fractures and the computational efficiency was also compared. After validation, we applied the EDFM method to perform history matching and production forecasting for an actual shale-gas well from Marcellus shale formation. Both simple and complex fracture geometries were considered and compared. Complex fracture geometry was predicted by a fracture propagation model considering natural fractures. Through history matching, conductivities of hydraulic fractures, active and non-active natural fractures were determined. The complex fracture geometry performs better in terms of productivity than the simple fracture geometry due to a larger amount of conductive fracture surface area. The simulation results based on an actual shale-gas well show that gas desorption and gas slippage significantly affects ultimate gas recovery, which can increase gas recovery after 30 years by 46.8%. Pressure-dependent matrix permeability and fracture conductivity play a negative impact on well productivity, which can reduce gas recovery after 30 years by 14%. Hence, complex fracture geometries and gas transport mechanisms should be properly accounted for in the numerical model in order to achieve more accurate long-term production forecasting of shale-gas wells.
Is API Enough for Gamma Ray Logs, or Do We Need More?
Authors: Inanc Feyzi , Vogt Andreas
Published: October 2018

Gamma-ray logs are so widely used in the industry that they can easily be classified as "commodity" services provided by large and very small service companies. In addition, gamma-ray tools are designed and produced by many companies. The wireline and logging-while-drilling (LWD) variants of this equipment present a large variability of these tools, their types and services. Although the standardization effort through the "API" definition helped end the chaotic outlook in the gamma-ray log world, it did not do much to elevate gamma-ray logs from the qualitative world to the quantitative world. Frequent complaints are still expressed about wireline and LWD tools not agreeing, different size LWD tools measuring differently, and logs from different service companies providing different results.

The major issue with gamma-ray logs is that the "API" definition is valid only if the tool is run in a 4.89-in. borehole filled with fresh water. Although all gamma-ray tools are supposed to provide the same results for such a well, in the real world there is no single one-size-fits-all concept. The measurements provided by tools characterized with the University of Houston (UH) GR pit standard will stray from a reading that can be relied on to be quantitatively correct. Although this is a well-known fact and there are environmental corrections available, no standard has been defined on how to develop the corrections. Service companies have their own internal correction approaches, resulting in a large variability from company to company. The gamma-ray logs obtained from different service companies are likely to differ from each other, even though they are corrected with their own correction algorithms.

The gold standard in LWD gamma-ray logging is the agreement between LWD gamma-ray logs and wireline logs. However, under what conditions they should agree with each other is far from clear. Can one expect a 6¾-in. LWD tool to deliver comparable logs to a wireline tool when both are run in 8½-in. holes with heavy mud? There should be clear-cut definitions of the conditions under which gamma-ray logs are compared to each other to qualify the agreement between the LWD and wireline gamma-ray tools.

In this paper we discuss the characterization process of the gamma-ray tools and how they behave in boreholes different than the UH GR characterization pit. Following that, we outline the proposals for developing gamma-ray correction strategies so that gamma-ray logs become quantitative logs rather than the qualitative logs of the past. This approach provides a second-level characterization of gamma-ray logs after the "API" standardization and provides insight for petrophysicists to understand the differences between the logs from different sources and to bring those logs together in a quantitative manner.
Real Time Surface Data Driven WOB Estimation and Control
Authors: Zha Yang , Ramsay Stacey , Pham Son
Published: October 2018

In directionally drilled oil and gas wells, wellbore friction and tortuosity play an important role on how efficiently torque and weight-on-bit (WOB) is transferred from surface to the drill bit. Providing accurate and consistent true WOB in a real-time manner is crucial to maintaining optimum drilling efficiency. In this paper, we present a novel, automated system for estimating and controlling downhole WOB in real-time using surface data.

The new system presented here automatically consumes drill-string and wellbore information while drilling to build a drill-string model with multiple sections, each with its own length, size, heading and wellbore friction factor. An automated algorithm captures and stores off-bottom hook-load data that meet certain rig-state conditions while monitoring multiple surface data streams. A numerical optimization method is then used to solve for the friction factor distribution with depth using selected off-bottom hookload data. The friction factors are put into a torque and drag model to estimate the downhole WOB. Numerical simulation shows that using the time history of surface data rather than a single hookload reading is key to ensuring a robust solution against noisy and missing data. An active control mode is also implemented in which the driller can directly control the downhole WOB through the system.

The system was field tested on multiple horizontal wells drilled by the operator. Comparisons with downhole measurements show the system is capable of accurately predicting downhole WOB throughout the well including the lateral section. Solving the friction model using historical hookload data ensures the stability and robustness of the estimation. The distribution of friction factors with depth also help provides additional assessment of wellbore quality. An automated WOB control test was also conducted to demonstrate the system's ability to directly control downhole WOB by adjusting surface WOB according to the algorithm. The new system provides a novel way to use real time surface data to estimate and control downhole WOB