bluuebunny/crossref_metadata_2025 huggingface dataset:
Reliable Carbonate Stimulation Using Distributed Temperature Sensing Diagnostics and Real-Time Fiber-Optic Coiled Tubing Intervention in Kuwait
Authors: Santin Y. , Matar K. , Montes E. , Gorgi S. , Joya J. , Bu-Mijdad M. , Al-Mubarak H. , Al-Lafi M. , Al-Hamad A. , Al-Askar H. , Al-Shamaa M. , Al-Enizi O. , Bu-Qurais A. , Madhavan S. , Al-Dashti M.
Published: October 2018

Injection profile enhancement has been one of the primary objectives for an operator in Kuwait. Stimulation interventions in injector wells directly affect the enhancement of oil recovery in producer wells. This paper presents the application of a verifiable stimulation intervention in a water injector well to help achieve the operator's objectives.

The intervention presented several challenges. There was limited information available for the newly drilled carbonate formation under consideration in the Greater Burgan Field. Additionally, the fiberglass well tubing required significant attention before running in hole (RIH) with coiled tubing (CT). A high concentration of H2S was identified in Formation A; therefore, gas returns were also a potential issue. This paper discusses the methods used to help address these challenges. During this case study, real-time fiber-optic cable CT (RTFOCT) technology was applied in the fiberglass tubing injector well to determine initial well injection profile and adjust treatment accordingly. This technology includes a fiber-optic cable integrated into the CT pipe and a modular sensing bottomhole assembly (BHA).

RTFOCT technology allows for rigless operations and performs interval diagnostics, stimulation treatment, and evaluation in a single CT run. During this case study, the well injectivity increased by more than 100%. Diagnostics and evaluation were performed by analyzing the well thermal profile using fiber-optic distributed temperature sensing (DTS). The BHA helped ensure accurate fluid placement during the treatment using real-time pressure, temperature, and depth-correlation sensors. The RTFOCT technology provided real-time downhole information that was used to analyze reservoir parameters, help ensure accurate fluid placement, and enable quick and smart decisions regarding the stimulation treatment stages based on the fluid intake in different zones. During injection, the heterogeneous fluid flow became homogeneous along the interval confirmed with the thermal-hydraulic model (THM). This helped reliably complete the intervention operations and delay possible water breakthrough in the producer wells and extended reservoir recovery.
Pushing the Thermal Stability Limits of Hydraulic Fracturing Fluids
Authors: Almubarak Tariq , Li Leiming , Nasr-El-Din Hisham , Ng Jun Hong , Sokhanvarian Khatere , Alkhaldi Mohammed , Almubarak Sama
Published: October 2018

In order to satisfy the demand for oil and gas, it becomes increasingly necessary to produce from formations that are deeper, have low permeability, and higher temperature. Conventionally, hydraulic fracturing fluids make use of viscosifiers such as guar and its derivatives to generate the rheological properties required during the fracturing process. However, to withstand the high-temperature environments, higher loadings of polymer is required. This leads to an increase in polymer and additive concentrations. Most importantly, these higher loading fluids do not break completely, and generate residual polymer fragments that can plug the formation and reduce fracture conductivity significantly.

This work builds on previous work which introduced a new hybrid dual polymer hydraulic fracturing fluid that was developed for high-temperature applications. The fluid consists of a guar derivative and a polyacrylamide-based synthetic polymer. Compared to conventional fracturing fluids, this new system is easily hydrated, requires less additives, can be mixed on the fly, and is capable of maintaining excellent rheological performance at low polymer loadings. In this work, the fluid is further optimized to withstand even higher temperatures up to 400°F.

Total polymer loadings of 30 lb/1,000 gal and 40 lb/1,000 gal dual polymer fracturing fluid were tested in this work and were prepared in the ratio of 1:1 and 1:2 (CMHPG: Synthetic). They were then crosslinked with a metallic crosslinker and placed in a HPHT rheometer to measure the viscosity between 200 and 400°F. After observing the failure temperature of the mixtures, additives such as buffers, crosslinking delayers, and oxygen scavengers were added and tested at temperatures above that point. The type of crosslinker used was also varied to observe the effects of the rate of release of the metallic crosslinker on thermal stability.

The results indicate that the 1:2 (CMHPG: Synthetic) mixture performed better at temperatures exceeding 330°F than the 1:1 mixture. The failure point of both mixtures was observed to be 350°F for the latter while the former failed at 370°F. The addition of a crosslinker that allowed a more controllable release was observed to improve the thermal stability of the fluid mixture above 370°F by increasing the polymer's shear tolerance. The addition of additives to the mixture was shown to improve the thermal stability of the solution to varying degrees. Of the three additives, the most significant enhancement came from the addition of oxygen scavengers while the least was from the buffer solution.
Geomechanics: A Key to Understanding the Underperformance of Fracture Treatments
Authors: Rahman Khalil
Published: October 2018

In many cases, the production prediction at the fracture design stage and later from the post-fracture pressure-matching exercise is never realized. The underperformance of fracture treatments is often attributed either to formation damage, proppant crushing and embedment, or to the poor reservoir quality despite a reasonably good reservoir property indicator from all sources including the pressure decline in a mini-fracture test. Based on several case studies, this paper highlights a number of issues that were found responsible for underperformance of fracture treatments. The understanding and mitigation of these issues require the application of comprehensive geomechanics.

For each case, a comprehensive geomechanical model was built for the field, characterizing the depth profiles of all three stresses, rock mechanical properties and the direction of the horizontal stresses by integrating available data from various sources including drilling and logging data, laboratory rock test data and mini-fracture test data. The contrasts in stress and rock mechanical properties among various lithologies along the well path were created based on fundamental geomechanical principles. The hydraulic fracture growth was simulated as per the pressure-matching practice for each treatment carried out. The production condition was applied to the simulated propped fracture to predict the production and compare it with the actual production data where available.

Issues that were found responsible for lower-than-expected production include (1) out-of-zone fracture growth that could not be predicted using the oversimplified geomechanics; (2) poor connection between wellbores and fractures for unfavorably oriented wells; (3) non-optimum perforation intervals that caused non-optimum fracture growth and near-perforation low conductivity; (4) malpractices in treatment execution that resulted in disconnected fractures with the perforations; and (5) suboptimal treatments for reservoir conditions. Appropriate mitigation strategies were recommended for wells in production, and increased productions were reported where the recommendations were implemented. One significant observation is that several oversimplified techniques currently used in the industry create significantly different stress contrast profiles than that was found based on fundamental physics of geomechanics, though all these profiles could be calibrated with the same closure pressure from a mini-fracture test. The use of such inaccurate stress contrast profiles is primarily responsible for unrealistic fracture and production predictions.
Ceramic Sand Screens: Qualification Strategy for a High Rate Gas Application
Authors: Cadogan Paul , Hall Steve , Jackson Richard , Meschke Frank , Read Trent , Gundemoni Bhargava , Barth Peter
Published: October 2018

As part of the overall Ichthys project there was a requirement to develop a remedial sand control application that would be suitable for installation should the sand production levels exceed the tolerance of the system. After an exhaustive review of available techniques, a remedial insert ceramic sand screen was selected as a potential option for these high rate gas wells. In order to be confident that the screen would be suitable for the application a comprehensive design and qualification plan was developed.

Due to the nature of the application and the technology itself the qualification programme was significantly more complex than typical oilfield equipment qualification; many of which can adopt standard API/ISO testing protocols with clear cut pass/fail criteria.

A number of specific elements were required to underpin the qualification. Firstly and perhaps most importantly was pre-qualification of the overall strategy itself. This can be thought of as the engineering work to endorse the approach, including the assessment of any inherent risks, and the development of the overarching qualification framework including understanding the dependencies between specific qualification work scopes.

Once the strategy was endorsed and the framework developed, a significant amount of time was spent maturing the testing programme and the subsequent pass/fail criteria, often involving extensive discussion with a number of specialised companies and especially the provider of the screen.

A thorough and extensive set of modelling and testing was conducted to endorse the final product for the application including fundamental FEA and CFD modelling through more traditional burst/collapse testing, end ring weld certification and corrosion studies to bespoke bending, impact and erosion testing.

In addition as this is a new technology and does not conform to any existing sand screen quality plan it was necessary to conduct a joint quality management system audit and screen manufacturing assessment. This led to the construction of an agreed Quality Control Plan; and specific production quality checks to ensure critical requirement conformance of the overall process and end product. The end result was a successfully qualified product for the Ichthys high rate gas remedial application.
Underbalanced Jetting in CSG play
Authors: Vatan Mike , Desplat Melanie , Giambalvo Anthony , Amorer Gabriel
Published: October 2018

Historically, openhole barefoot completions used in conjunction with cavitation and surging or underreaming techniques, have proven to be an effective way to stimulate coal seam gas wells to increase effective permeability. (Logan et al, 1989). However, despite having a positive impact on production, the unpredictable time required to cavitate and surge the wells can be substantial, sometimes requiring up to 4 weeks to execute required scope. This time consuming technique leaves the operator vulnerable, working in an unstable borehole where fishing operations are common and the outcome of delivering scope is not guaranteed. The main challenges of accurately predicting cost to keep the projects economical, continuing to produce coal fines during cavitating and surging, and continual sloughing are some major drawbacks.

The other alternative on the market is underreaming, which has its own limitation in relation to the maximum possible enlargement of the borehole or more specifically, the size of the underreamer that can be utilized. Faced with these limitations, there was a significant need for an innovative way to stimulate wells to increase production while minimizing costs.

This paper introduces the ingenious use of a newly designed jetting tool, with specialized nozzles, to enlarge a borehole size using a combination of air and mist. This case study conducts a lookback on design parameters, cost, and safety improvements introduced by this new technology.
Pump-Out Stage Tool and Pump-Out Float Collar System Enhances Completion Efficiency in Queensland Coal-Seam Gas Project: A Case Study
Authors: Zaman Mohammad , Dunn Timothy , Tickoo Sandeep
Published: October 2018

This case study highlights the field-trial of a pump-out stage tool, pump-out float collar, and the annular casing packer. These technologies were integral to drilling and completing wells in the Santos coal-seam gas (CSG) development of the Roma field in the Surat Basin of southeast Queensland.

Pump-out systems—which allow a primary cementing job to be performed above a slotted casing string using a pump-out stage tool, annular casing packer, and pump-out float equipment—eliminate the need for drill out operations. Once the casing is landed, a ball is deployed from surface to actuate the inflation of an annular casing packer below the stage tool and above the slotted casing. A second ball is deployed to shear and shift a sleeve to open the stage tool and begin the primary cement job. Once complete, a cementing wiper plug is released from surface and pumped behind the cement slurry to shift the stage tool into the closed position. The internal pump-out casing components are displaced to the bottom of the well and require no further intervention.

This case history includes results of the initial field-trial runs and technical details on well configurations, slotted liner placement across the coal-bed intervals, pressure charts, cement-job data, shear information on the ball seat, detail on the stage-tool operation, pumping out the float collar, and displacement of the internal equipment downhole. These jobs planned to eliminate the need to run a dedicated drillout trip during initial completion and also the need to change out the pipe rams in the blowout preventer (BOP).

Ultimately, the pump-out system provides a full-bore casing geometry with no internal restrictions and is expected to reduce completion costs by 15%.
Injectivity and Well Deliverability Test and Analysis in an Offshore Complex High CO2 Gas Carbonate Asset
Authors: Masoudi Rahim , Abd. Wahab Muhammad Afiq , Motaei Eghbal , Ataei Abdolrahim
Published: October 2018

Among the key uncertainties and risks as part of development of a high CO2 offshore gas carbonate field; production well deliverability, produced CO2 management, and cap rock integrity have been identified as potential techno-commercial showstoppers that need further appraisal and studies. CO2 storage and sequestration in the aquifer of the same field was identified as the most feasible and economic option for the Produced CO2 management and hence the injectivity within the targeted intervals and aquifer become part of the appraisal and study scope.

An extensive over 200 m coring program covering various intervals including overburden, caprock, carbonate hydrocarbon intervals and aquifer has been designed as part of data acquisition and surveillance plan. The main plan scope were designed as:To establish reservoir properties & characterizationTo measure formation pressure and acquire fluid sampleTo establish reservoir injectivity and productivity at the prospective intervalsTo acquire data for flow assurance analysis, facilities design and well material selection studies for development planning.

The test and analysis has been successfully conducted covering the intended scope of the plan. Based on the Well test and PTA, the reservoir permeability is calculated and is more or less aligned with the core permeability with the total high skin which the majority comes from geometrical/limited-entry skin. The productivity index is calculated to be 21 STB/day/psi. There is difficulty to analyze the Injectivity test due to non-isothermal effects during injection and fall-off test where the fluid property of both injected water and reservoir water is a function of temperature and time. An approximate method is applied using the average temperature during the fall-off to simplify the case by considering a constant fluid property. Injectivity Index is estimated from rate and pressure data to be around 26 STB/day/psi. However, it declined by time to reach a value close to 13 STB/day/psi. In the second test, Based on pressure transient analysis the homogeneous, vertical well with limited entry, and infinite boundary model with underneath aquifer was accepted as representative for S2 reservoir. To capture the non-Darcy effect, the rate dependent skin model is selected. Non-Darcy coefficient is extracted from well model for IRP in well model (1.0073E-4 (Mscf/day)-1.

Generally, the well test and injectivity and productivity analysis objectives are achieved as the fluid type is also confirmed. The paper will detail out the actual test results, methodology and evaluation approaches in this surveillance plan.
A Priori Scenario Modelling with LWD Seismic for Successful Well Placement
Authors: Tan Aaron , Lee Bor Seng , Van Voorst Vader Herman , Holleman Nico , Spiteri Richard , Ahmed Aqil , Maula Fahdi , Shamsuddin Shanaz , Heng Elijah
Published: October 2018

A Vertical Seismic Profile acquired while drilling and which utilized an a priori velocity model template to facilitate accurate well landing in a constrained drilling section is presented. The results were compared to original predictions based on surface seismic and actual formation depths taken from log data.

The approach used actual checkshot velocities acquired in real time using VSP lookahead imaging while drilling to reduce spatial and depth uncertainty. Projections ahead of the well landing utilized the checkshot data to perturb the a priori velocity templates in real time. It was also complemented by the borehole seismic image to check for sub-seismic faults and alternate interpretations. Based on these projections, trajectory corrections were made to optimize landing the well in a key reservoir sand. Initiating early directional changes were critical to land on a short, directionally-constrained open-hole section whilst ensuring the section was within the targeted fault block.

A comparison of the actual wellbore velocities against the predrill scenarios is provided along with corresponding vertical depth predictions. Lateral constraint was provided by the correlations of the VSP with the surface seismic image at key stages while drilling. Mapping of the drilling data to the velocity templates showed a deep case scenario for well placement. Details of the two resultant trajectory changes initiated after 2 and 5 stands of drilling respectively are explained. The approach allowed for accurate well placement, reducing depth uncertainty from 60-100 ft. predrill to within 5 ft from final while drilling prediction to actual depth. Final depth confirmation utilized Gamma Ray and Resistivity at Bit Inclination (GABI and RABI) for the key sand. The sand was found to be 18 ft. deeper than initially expected based on the pre-drill model. This method saved the drillers a potential side track.

Conventional Electromagnetic well placement techniques can be limited in short open-hole sections where early time information is required to facilitate trajectory changes to allow for correct spatial landings. By using VSP while drilling in conjunction with a priori modelling, data can be acquired early enough to successfully, address this challenge.
Facility Operations Readiness and Project Start-Up Support and Integration
Authors: Maher Michael
Published: October 2018

The Australia Pacific LNG (APLNG) Downstream Project comprised construction of a two-train LNG plant, two 160,000 m3 LNG storage tanks, a LNG loading jetty, and associated infrastructure on Curtis Island, near Gladstone, Queensland. The facility utilises ConocoPhillips’ proprietary Optimized Cascade ® process to liquefy natural gas. Project planning began in 2008 and construction commenced in 2011. LNG production from Train 1 began in December 2015 and Train 2 came on line in October 2016. In August 2017, the final 90-day two-train lenders test was successfully concluded and included an operational component in which the LNG Facility operated at ten per cent above nameplate capacity for the 90-day period. This successful outcome was achieved through collaboration, integration and robust execution plans by the APLNG Operations, APLNG Project, ConocoPhillips LNG Technology and Licensing and Commissioning and Start-up work teams. In an effective strategy to support the drive to APLNG first cargo, the combined teams formed a fully Integrated Completions Team in 2015. This team worked together enabling rapid development of the operations workforce capability and resulted in both trains achieving performance tests at first attempt.

The APLNG Project operability assurance and operations readiness program commenced with a collaborative workshop, attended by Operations, Projects and Commissioning and Start-up representatives. A focus on high collaboration and integration between the teams backed by ConocoPhillips’ Operability Assurance (OA) and Operations Readiness (OR) principles identified 370 critical business deliverables. Learnings were leveraged from across ConocoPhillips assets (including Darwin LNG) as they pertained to readiness best practice. APLNG Readiness Assurance guidance was established to create specific functional readiness trackers to measure every action supporting the 370 deliverables. A simple and effective tool was developed and supported by robust monthly review forums where each action was tracked and rolled up to S-Curves. These deliverables translated to over 7,000 unique line items tracked over the entirety of the readiness implementation. This work was leveraged by the Integrated Completions Team which implemented robust lessons learned from Train 1 to realize immediate results, delivering a 33% reduction in the Train 2 start-up schedule.

The combined efforts of the teams delivered two highly operational trains within the 2016 calendar year resulting in the production of additional cargoes. The successful execution and implementation of OA/OR principles combined with strong integration of APLNG Operations into the APLNG Project phase laid the foundation for exceptional first year operational and production performance. This meant the APLNG Operations Team moved from a newly formed team to a high functioning and critically evolving team in support of the APLNG Downstream LNG Facility.
Integrated Modelling Workflow for Life Cycle Development of a Large Scale Coal Seam Gas Field
Authors: Sharma Vikram , Davies Josh , Vella Benjamin , Jiang Jesscia , Sugiarto Isan , Mazumder Saikat
Published: October 2018

Development of coal seam gas fields is conceptually simple but complexity arises with: the stochastic nature of coal reservoirscontinually changing work scopethe large number of wells required to meet gas contracts.

In the current environment, the cost of developing thousands of wells and hundreds of kilometres of associated gathering is a key driver to the success or failure of CSG projects. Continuous reduction in cost/funding with limited resources drives companies to derive an integrated approach to the field development.

Subsurface models now form an integral part of production forecasting and decision making. Companies have benefited from the computation technological advances in the recent past, whereby it is possible to run large-scale models in a reasonable timeframe. Several tools and approaches are available today to integrate complex 3D reservoir models with surface networks to generate an integrated production forecast. In this paper we focus on using advanced geospatial applications with integrated system models to derive a development concept which is optimal, realistic and capable of adapting to changes in work scope as the development progresses. Gathering routes and associated material take off (MTO) points are generated in geographic information system (GIS) tools, using constraints and criteria such as: access and approvalssub-surface data (scope of recovery maps, net coal and permeability)maximum use of existing infrastructure (Roads, Tracks, etc.)environmental constraints (overland flow, vegetation, etc.)well spacing.

Seamless integration of GIS tools and sub-surface modeling tools is what makes this workflow unique. GIS tools acts as a key integrator, forcing different disciplines and departments to work together in a common platform. It also functions as a common database used across an entire organisation. GIS toolbox gives a significant head-start to the project by first defining what is achievable. It is then finessed with the best value sub-surface outcome and a final forecast is derived in a significantly shorter time scale. With the approach presented in this paper, the forecasting cycle, involving full economic run, is substantially reduced– from several months to just weeks, if not days. The final outcome is an achievable well sequence which is derived along a realistic gathering route. With this, the MTO and the production forecasts are aligned and the associated costs can be easily traced to source. This workflow is automated and can be easily repeated if scope or project premise changes. Last but not least, this approach can be applied to any onshore unconventional or conventional plays.
Successful Hydraulic Fracturing Optimisation in KS Field through Fracture Height Growth Identification and Mitigation
Authors: Kamal Hamzah , Noke Fajar Prakoso , Geraldus Yudhanto , Luciana Soetikno , Ricki Daniel Marbun , Reza Vitali , Areiyando Makmun , Apollinaris Stefanus Leo Anis
Published: October 2018

Hydraulic fracturing in the tight sandstone of the KS Field has been implemented in more than 200 wells since 2002. Year by year, it gets more challenging due to limited well candidates with good properties and a decreasing trend in production result. Thus, hydraulic fracturing optimization both in design and execution are critical to increase success ratio and to contribute more oil production. One of the efforts is delivering fit-to-purpose design through fracture height growth identification and mitigation.

A mechanical earth model (MEM) is constructed to obtain elastic properties and stress profile as an input for fracture geometry simulation as a preliminary tool for height growth prediction. The MEM is generated using triple combo and sonic logs and validated with wellbore stability analysis. A pre-treatment mini-frac was performed and analyzed before the main fracturing operation to calibrate and update the MEM stress profile. For final validation, the profiles of MEM, MEM optimized fracture simulation and temperature log results are compared to evaluate the fracture height growth issue. Last, fit-for-purpose strategies are applied to optimize the fracture geometry result and maximize oil production.

Previously, hydraulic fracturing with high proppant volume has been used to create long fracture half-length providing large reservoir contact and thus improved productivity. Unfortunately, production after fracturing in some wells shows no significant change and occasionally yields high water cut. Currently, detailed pre-fracturing evaluation is applied. Comparison plot results show fracture growth consistency between the MEM-optimized hydraulic fracturing simulation with temperature log profiles, validating the suspicion of fracture height growth to and through the upper and lower barriers of the fracturing target.

Two design changes were then proposed to control fracture height growth: Applying lower-viscosity fracturing fluid by decreasing gel loading or changing to viscoelastic surfactant fluid; and applying an artificial barrier technique. These changes are designed to reduce fracture height growth and increase effective fracture half-length in the pay zone. The result is increasing fracturing success ratio, from 40% to 70%, which contributes to arresting the production decline of the KS Field.

Integrating geomechanics analysis (in the form of MEM) into hydraulic fracturing design simulation and profile comparison, MEM-optimized hydraulic fracturing simulation and temperature logs have validated the issue of fracture height growth problems in the KS Field and justified the application of fit-for-purpose strategies to mitigate the issue.
Integrated Operations for Gas Lift Optimization: A Successful Story at Peninsular Malaysia Field
Authors: Anuar Wan Mohamad , Badawy Khaled , Bakar Khairul Azhar , Aznam Mohd Razik , Salahuddin Siti Nur , Mail Morris , Bakar Afdzal Hizamal , Trivedi Rajesh , Tri Nghia Vo
Published: October 2018

Gas Lift Optimization solutions have improved significantly over the past decades with the introduction of Integrated Operation (IO) in the Oil and Gas industry.

Big fields that consist of hundreds of strings, gas lift injection system, water/gas injection system and complex surface facilities (compressors, pumps, choke and valve, etc.) could establish numerous cases from different scenarios to identify production bottlenecks via simulated network models.

Using available tools, the user could model the full production system including well, surface network, reservoir, gas/water injection models, gas lift injection networks and process plants to identify bottlenecks and opportunities for optimization. The model is updated continuously using live data feed and automated technical workflow to establish an end to end solution in providing various optimization scenarios e.g. Gas Lift Optimization.

This paper discusses how the methodology works and reviews the results of gas lift optimization from four platforms consisting of over 200 strings of which 95% are gas lifted, operated using a new approach that includes live link to field data, integrated model management, and automated technical workflows to identify potential strings and gas lift supply facilities for production enhancement. This paper reviews the setup required to ensure all the necessary inputs are aligned to publish the desired outcome.

The approach has resulted in prevention of 480bopd potential deferment at platform level that can be further improved with future field implementation. In addition to gas lift optimization, the workflows have potential to expand to other business needs such as defining an accurate gas demand requirement, determining daily liquid or sand production limitation identifying underperforming wells, optimizing choke configuration, studying the feasibility of low pressure system, water treatment system, and condensate recovery system.

This paper should be of interest to those who are planning to implement Integrated Operations to their field with the aim in maximizing its value. It will provide information on the requirements, challenges, ways to overcome, and effective approach during the implementation.
An Efficient Approach for History-Matching Coal Seam Gas CSG Wells Production
Authors: Chang Gladys , Gizat Aibassov
Published: October 2018

QGC's current full-field reservoir model comprises hundreds to thousands of CSG wells. This presents a considerable challenge from a history-matching standpoint compared to a conventional workflow where well-level adjustments may be made on one well at a time. In QGC, a model with an improved well-level match is desired as the resulting well forecast will enable decisions on a well-level to be made more confidently, such as the prioritization of well workovers. Previously a field-level history-match was deemed acceptable when the model was only used for field development planning.

The method parameterizes the well-level relative error in simulated production from the model versus observed production. The workflow utilizes this data, known as well-level modifiers, to alter subsurface properties. This has been achieved with a semi-automated workflow to make the process efficient and repeatable, but also to enable engineering judgement to be incorporated in the history-matching process. The feedback loop is also an essential component of the workflow as it allows the well-level modifiers to be sense checked against the regional geological trends. This further encourages collaboration within a multi-disciplinary team.

These well-level modifiers can also be used to create history-match metrics, which can be spatially mapped to help target specific areas for improvement in history-match quality. Some powerful use of visualization techniques discussed in this paper has not only minimized the mismatch but ensures the characteristics of the production history and geological trends are honoured to assure the robustness of the history-match and the resulting model predictability. The workflow has significantly reduced the time and efforts spent in delivering an improved well forecast when required. The technical development community in QGC has actively nurtured a culture of ideas sharing and innovation, which made the development of this workflow possible.
Optimising Horizontal Coal Seam Gas Wells by Combining Reservoir Simulation and Transient Well Modelling
Authors: Nuralishahi Turaj , Vahmani Maryam , Dharma Putra Erni , Hsiao Wun Moh , Kumar Thakur Kapil , Wai Aung Phyoe , Coman Chris , Delfani Saba , Wimbridge Kyle , Rodriguez Nelson , Samaan Johny
Published: October 2018

In 2017, APLNG drilled the first horizontal wells within the Surat Basin targeting the Walloon coal seam gas (CSG) measures. This reservoir is quite shallow with the potential for relatively low pressures. To address this uncertainty, a study was performed to identify an optimum operational strategy to maximise the cumulative gas production of a well over the first five years of production.

This was achieved by using a Latin Hypercube sampler and a Genetic Algorithm optimiser to identify optimum reservoir simulation scenarios. The optimized simulation scenarios were then modelled within a multiphase transient simulation model, to better understand the flow regime behaviour within the wellbore. This predicted the flowing potential of the well whilst modelling flow assurance risks such as wellbore slugging. The result was an innovative workflow that identified optimum operational strategies whilst accounting for the uncertainties in reservoir pressure and the fluid hydraulics in the wellbore.

After completing the reservoir optimisation studies, the optimised cumulative gas production showed increases between 3% – 6% compared to the base case. Other improvements included; higher peak gas production, higher peak water production resulting in earlier desorption of gas, shorter time to initial gas, and shorter time to peak gas. After running the optimised reservoir simulation cases through the transient models, it was found that the days to peak gas was reduced by 80-90%, whilst the slugging periods were reduced by 90-100%. The models were also used to quantify the impacts of changing operational/design parameters such as horizontal well length, casing sizes, pump speeds, and choke settings. APLNG used these results to design their well start-up and ramp-up strategies, and successfully kick off their horizontal wells.

The results of this innovative workflow for reservoir and wellbore modelling in a CSG field highlights the new insights that can be gained by combining traditional reservoir simulation with mathematical optimization and transient well flow modelling. These workflows enhance our understanding of how to improve efficiencies and maximise production volumes within CSG fields.
Analytical and Numerical Solutions for Interpretation of Chemical Compaction in Chalk
Authors: Andersen Pål Østebø , Berawala Dhruvit Satishchandra
Published: October 2018

Chemically reactive flow is of significant importance for EOR due to possible wettability alteration (low salinity and smart water brines), scaling and chemically enhanced compaction, which all can affect hydrocarbon transportation. In particular, chalks (Ekofisk, Valhall) are highly sensitive to the composition of the injected brine (typically modified seawater) as demonstrated on lab and field scale. We present numerical and analytical solutions to interpret the link between geochemical alterations and creep compaction in chalk cores.

A 1D core scale model is proposed for interpreting geochemical compaction during reactive brine injection into chalk cores loaded uniaxially in creep state (compaction under constant applied effective stresses). An analytical solution is derived to describe the steady state ion and dissolution rate distributions. An analytical model for creep compaction is proposed based on the applied affective stress and the rocks ability to carry that stress as function of porosity. The two models are coupled as follows: The compaction rate is assumed enhanced by the dissolution rate. Further, the solid volume changes by mineral dissolution and precipitation, also affecting the compaction rate. Brine-dependent and non-uniform compaction is therefore built into the model via the dissolution rate distribution.

The model is validated against data from ~ 25 core samples where simple Mg-Ca-Na-Cl brines were injected at Ekofisk reservoir conditions (130 °C), in particular experimentally measured effluent concentrations, distributions in mineralogy after flooding and creep compaction behavior. The model captures the effect of varying key parameters such as brine composition, injection rate and initial porosity and can predict ionic and mineralogical profiles along the core, axial and radial deformation profiles locally and with time. This model is a highly useful tool for interpreting experimental data, predicting in-situ mineralogical distributions where measurements have not been made, and for predicting compaction behavior at changes in brine composition, injection rate or effective stress.

The model is intended for giving a prediction of qualitative and quantitative trends during flooding-compaction tests in chalks. The model and its methodology are translatable to other systems but is validated for lab measurements on chalk samples. Current modeling approaches do not consider the complex interplay between brine and rock compositions, reaction and compaction. This work aims to contribute to the current understanding of this topic.
Edge Analytics and Future of Upstream Automation
Authors: Saghir Fahd , Gilabert Helenio , Boujonnier Matthieu
Published: October 2018

As data processing capabilities improve electronic device performance, it becomes necessary for Oil and Gas operators to understand how computing power can be harnessed at the extremities of their production network by deploying Edge Analytics solutions.

This paper will discuss adapting the Industrial Internet of Things (IIoT) in the Upstream Automation domain, specifically in Artificial Lift assisted production, and will shed light on how Edge Analytics can be leveraged to deploy Machine Learning Models (MLMs) directly at the well-head.
A Review of Current Knowledge with Geomechanical Fault Reactivation Modelling: The Importance of CO2 Mechano-Chemical Effects for CO2 Sequestration
Authors: Altaf Iftikhar , Towler Brian , Underschultz James , Hurter Suzanne , Johnson Raymond
Published: October 2018

A fault stability study constitutes a fundamental element of any subsurface injection project that involves faults within a storage complex, yet the transient geomechanical effects introduced due to CO2-rock chemical interactions are rarely considered. This paper presents a review of the published work investigating the potential alteration of rock properties due to short to long term CO2-host rock chemical interactions during commercial scale carbon capture and storage (CCS) operations. Furthermore, the authors of this paper are attempting to highlight the potential significance of these mechanical-chemical effect on the fault reactivation potential for a commercial scale carbon capture and storage (CCS) operation.

The reactive nature between CO2 dissolved in formation water and the storage reservoir can significantly alter the hydraulic and mechanical properties of the host rock, which could in turn affect the storage potential of the target reservoir. Alteration of the host rock mineralogy due to chemical interactions with CO2 have been well studied (Farquhar et al. 2015), but little is available in the published literature on the resulting changes in rock elastic properties (i.e. Young's modulus and Poisson's ratio) due to these reactions. Some recent experimental studies have suggested significant changes in rock properties occur. When we incorporated the geomechanical effects, induced by the rock elastic property changes documented in these published cases, into both 1D analytical and 3D numerical models based fault stability analyses for a Surat Basin reservoir, we observed significant modification of the reservoir storage capacity prior to reaching fault reactivation criteria.

Based on our review of the published literature and our fault stability analyses, we conclude that the chemical effects of CO2 interaction with host rock needs to be experimentally tested to confirm if these effects are significant. If yes, then these effects should constitute an integral part of the geomechanical study for any large scale CO2 injection exercise if there is a critically stressed fault as part of the storage complex.
CSG Reservoir Monitoring Technology: Advantages, Challenges and Selection Criteria Queensland Case Study
Authors: Mortezapour Amin , Bassat Abdul , Lean Eugene
Published: October 2018

Application of reservoir monitoring systems has great value in facilitating the understanding of reservoir behavior and complexity, efficient production optimization and reservoir management over time. The technology has been well accepted by oil and gas pioneers globally in the last 32 years (Australia, Venezuela, Colombia, Kuwait, Oman, Norway, China and USA). In the past 10 years, more than 1,000 wells have used reservoir monitoring systems to monitor the well and reservoir performance of coal seam gas (CSG) wells in Queensland. This paper presents technology, reservoir and production engineering analysis and failure mechanisms in more than 600 CSG wells in Queensland. This paper postulates the selection criteria for every specific application. Some services companies has a 8-year history of installing different types of gauges as one of the main reservoir monitoring technologies for different operators in Australia and New Zealand (The majority of this technology is based in the State of Queensland due to business and regulatory requirements). The application of technology helps CSG operators in the following capacities: Optimizing pump performance and water level monitoringOptimizing hydraulic fracture performance, ground water movement and modellingPressure data for the history matching process (Reservoir Engineering Application)Multizone pressure monitoring (gas injection performance, etc.)

Specific application of the technology, findings during the installation, monitoring, operation, typical completion scheme and best practices for coal reservoir monitoring are summeraized in this paper.
Rate Transient Analysis RTA and Its Application for Well Connectivity Analysis: An Integrated Production Driven Reservoir Characterization and a Case Study
Authors: Ataei Abdolrahim , Motaei Eghbal , Yazdi Mohammad Ebrahim , Masoudi Rahim , Bashir Aamir
Published: October 2018

Rate Transient Analysis (RTA) has been used in gas reservoirs as a proven method for reserve estimation, well diagnostic and production performance evaluations. The authors have demonstrated several case studies showing the application of production analysis (PA) for reservoir characterization in gas and single phase oil reservoirs previously (Motaei, 2017, Ghanei and Ataei 2017, Ataei 2018). The adopted method for Integrated Production Analysis (IPA) works well in those case studies after combining the available data from RTA, PTA, or Material balance and basic reservoir engineering tools. The RTA found to be completing those is based on simple production data analysis using flowing data rather than limited shut in and less accurate ones. With benefit of continuous monitoring of FBHP using PDG, it is possible to evaluate the interferences and boundary in distance beside conventional reservoir properties like permeability and skin.

These methods were found to be extremely powerful and popular particularly with the high resolution data from pressure downhole gauges (PDG).

In this paper we have analyzed the available production data from a gas reservoir in offshore environment in South East Asia. It has been developed with five high PI wells and smart completion and monitored closely with PDG and other surveillance data to understand the contact movement during the production history. Due to the complexity of the field, different methods of production data analysis were used to understand the production performances. The recent advances in RTA allows us to apply the classical single well analysis method to a multiple well and multiple phase flow using Generalized Pseudo Pressure (GPP).

The previously published workflow by the authors (Ghanei and Ataei, 2017) is used for this case study. We evaluate this technique for a multi well gas field with advancing aquifer. The connected volumes as estimated by single well analysis will be used for a group of wells which are communicating and have interference. We have also used a simple reservoir modelling approach to define scenarios which fit the production data and can be used for forecasting which can potentially save study teams time when deciding on the potential value and defining the targets of a major infill drilling project.
Minimum Stress, Maximum Pressure: A New High Performance Bridging System Facilitates Drilling Depleted Formations at High Overbalance in Middle East
Authors: Addagalla Ajay , Maley Iain , Lawal Ishaq , Jadhav Prakash , Luigi Moroni
Published: October 2018

Wells drilled in the direction of minimum stress are potentially more favorable for reservoir development and optimal production. In such a situation, hydraulic fractures grow transversely to the wellbore axis, allowing placement of multiple fractures without the overlapping fractures. However, wells that have been drilled in the minimum horizontal stress direction typically encounter drilling-related problems such as stuck pipe, wellbore breakout and lost circulation. These problems can result in increased well costs due to significant periods of non-productive time and in the worst case, loss of the well.

To address this, wellbore strengthening techniques can be applied to bridge or plug fractures and increase near-wellbore stability via hoop stresses. Designing drilling fluids from a wellbore strengthening point of view has proved successful at managing problems associated with wells that have high overbalance pressure and low formation strength. As more challenging wells are drilled, though, overbalance pressures are exceeding the wellbore strengthening capabilities of existing fluid designs. These high-overbalance pressures significantly increase the risks associated with drilling in the minimum stress direction.

This paper describes an improved, environmentally acceptable, customized high-performance system that can be used in water-based and oil-based mud systems, enabling wells to be drilled with more than 4500 psi overbalance pressure and mud weights beyond 145 pcf. This newly designed system helps the operator increase operational efficiency by:Minimizing the risk of differential stickingReducing downhole lossesImproving wellbore stabilityReducing torque and drag through enhanced lubricity

Laboratory data is presented outlining the design of the new system and field case studies show how this new, improved bridging system reduces the risks associated with drilling in the minimum stress direction through highly depleted reservoirs or reservoir sections where multiple targets may be separated by high-pressure zones that require higher mud weights.