bluuebunny/crossref_metadata_2025 huggingface dataset:
Comparison of CO2-EOR Performance between Offshore and Onshore Environments
Authors: Ghanbari S. , Mackay E. J. , Pickup G. E.
Published: March 2016

Despite a successful history of CO2-EOR onshore, its application has been limited offshore. There are fundamental differences between offshore and onshore environments. Offshore, reservoirs are typically bigger and are characterised by larger well spacing. There are also other important differences in terms of prevailing reservoir conditions. This study compares the performance of CO2 flooding between these environments and investigates how the combinations of these differences affect the performance of CO2-EOR offshore compared to onshore. Two synthetic box models with different dimensions, each representing a relevant environment were constructed and the CO2 flooding process were simulated. Onshore model represents a United States CO2 flooded reservoir, while offshore model represents a North Sea reservoir. The offshore model is thicker and has larger well spacing. The same injection and production rate in terms of pore volume and the same flood strategy were applied in both models. Identical flooding strategy ensures that both models experience the same average pressure evolution during simulations and the injected CO2 volumes remain comparable. This also makes the results comparable between them. The results show that, larger well spacing offshore favourably affects the pressure evolution of the system. The higher injection pressures offshore coupled with high CO2 compressibility, makes CO2 and reservoir fluid densities become comparable offshore, which reduces the gravity segregation of CO2 and increases CO2 and reservoir fluids compositional interactions. The same rate of depletion in a larger well spacing environment translates to higher fluid velocities inside the reservoir, which makes the flow less affected by gravity. Offshore, the model thickness is comparable with well spacing which retards the gravity segregation of CO2.

The inclusion of other differences mainly reservoir temperature and formation permeability characteristics of offshore environment adversely affects the CO2 flood performance offshore. This poor performance however can be compensated by operating the flood at higher pressures. The results show that the CO2 flood offshore is less gravity dominated and WAG does not bring the same benefit offshore as it does onshore. Numerous simulations confirmed that there is always a correlation between EOR and CCS performance of the system. Scale differences can bring improvements for CO2 application offshore characterised by thicker pays and larger well spacing. However this improvement may not be able to compensate for the adverse effects of the prevailing reservoir conditions. Given other considerations regarding CO2 application offshore (e.g. production problems) the in-situ reservoir conditions may make the EOR performance of the CO2 flood so poor that further motivations like CCS will be required to bring CO2 injection offshore.
Development of Degradable Seal Elements for Fully Degradable Frac Plugs
Authors: Takahashi Takeo , Takahashi Shinya , Okura Masayuki
Published: March 2016

Demand for hydrocarbons is continuing to grow, leading to an increase in the stage count of hydraulic fracturing in unconventional reservoirs. The plug-and-perf system is a typical stimulation method that uses frac plugs for zone isolation. Conventionally, the plugs must be milled out to recover the flow path for hydrocarbons after fracturing is complete. Fully degradable frac plugs would eliminate the need for milling out, and this in turn allows for longer wellbores in the lateral direction, lower costs, and reduced risk in well completion. A key material for fully degradable frac plugs is a sufficiently degradable rubber with good sealing properties for the seal elements of the plugs. This paper presents the fundamental properties of degradable rubbers developed in a comprehensive materials study. The degradation behaviors of the degradable rubbers were investigated under various temperature and fluid media conditions. The mechanical strength was compared with that of conventional nitrile rubber. Nonlinear, three-dimensional multi-body contact analysis and qualification testing were integrated to estimate the sealing performance of seal elements made of the degradable rubbers.
Effective Water-Injection Measurement in Deepwater Operation Using Field Tested Tool
Authors: Udofia Emmanuel , Eruja Femi , Benjamin Obong
Published: March 2016

Bonga deepwater field depends on sustained water-injection for reservoir pressure maintenance for efficient oil production. The field which lies 120km southwest Niger Delta in Nigeria at a water depth of 1000m, has varying flow rates in the producer wells with very fast response to changes in injection rates and has been developed with seventeen water-injectors to provide pressure support for the producer wells. All water injectors are fitted with subsea water-injection meters for measurement of actual injected water. The subsea infrastructure is such that the water injection wells are developed into two wings (Eastside and Westside) and serviced by two flow-header meters into each wing. Each wing consist of several water-injector wells, therefore measurement of water-injection into each well is crucial.

Since early 2011, the individual wells subsea water-injector measurement meters became faulty and we were unable to accurately measure the individual water injector's well rates due to the inconsistency of the subsea meter and efforts to fix the meters were not successful. As a result, the optimisation of oil production based on efficient water-injection was hampered because there was a high uncertainty of the water injection figures.

The proposed solution was to install Field ware Production Universe EOR, which is a state-of-the-art, real-time data driven application for water-injection monitoring. The procedure is to use a multi-rate injection well test from the bulk water-injection meter for data acquisition and build the Production Universe EOR model for subsequent rate estimation for individual water-injectors. The deployment of this application enhances efficient production optimisation effort in Bonga field through accurate measurement of the injected water into each injector well.

The result from this empirically based work shows how a quick solution for estimating water injection into each water-injector could be achieved. This reference tool could be applied to other operating units having similar challenges like Bonga field especially in a deepwater environment with high cost of intervention to replace such faulty measurement meters.
Pressure Transient Behavior of Partially Naturally Fractured Reservoirs
Authors: Qasem Fuad
Published: March 2016

Naturally fractured reservoirs (NFRs) always have flow networks that are more or less irregular, discontinuous, or clustered. NFR with such spatially non-uniform distribution of fractures is called partially naturally fractured reservoir (PNFR). An improved understanding of pressure response is required to characterize PNFR. This paper presents a better understanding of well test pressure response of PNFR.

Stochastic modeling was used to generate various geological models with different fracture intensities. Single phase liquid flow through stochastically generated reservoirs is simulated by a numerical reservoir simulator. Dual-porosity / dual-permeability model was selected to simulate PNFR. A vast database of pressure transient responses of the reservoirs with varying fracture intensity, matrix permeability and fracture porosity is presented in this paper. Pressure derivative was used to analyze the pressure transient responses.

Pressure derivative analysis indicates multiple V-shapes representing various sets of fracture intensities. It is observed that with the increase of fracture porosity V-shape become more pronounced. It is also observed that with the increase of matrix permeability, the duration of composit radial flow is prolonged. The shapes of pressure drawdown plots indicate the level of fracture connectivity of the reservoir. Whereas the fracture connectivity is related to the fracture intensity (FI). The critical value of fracture intensity is observed around 60 percent which results in the formation of connected fracture network.

The interpretation of pressure responses of PNFR becomes very difficult and challenging because the available simplified models do not relate to reality of reservoirs. This paper quantifies the fracture intensity for a broad range of PNFR with the use of pressure transient responses. This quantification is a major contribution to the present literature.
Modern Jack-Up Design Solutions for Mature Markets
Authors: Baan Rutger , van der List Remco
Published: March 2016

In mature oil and gas fields particularly in the Middle East, India, Gulf of Mexico, West Africa and Asia, a specific footprint is required due to earlier campaigns. The key reference is the LeTourneau-116 design. With its specific footprint, it is the most widely used jack-up design in these regions. The CJ43 drilling jack-up, based on its successful predecessors, is the modern replacement and sets a new standard for jack-up drilling rigs used in mature oil and gas fields.

Drilling technology has evolved over the years. The focus has been on drilling equipment reliability, mechanization, partial automation and advanced well control. However, when reviewing the overall jack-up technology – excluding the drilling related equipment – a large part of what has been ordered recently resembles the same design philosophy of thirty to forty years ago. No significant changes on the jack-up design to improve its capabilities in terms of uptime, efficiency, material handling, maintenance, redundancy of critical systems and elements to improve human life on board.

But, when applying innovative technology, a more modern jack-up design such as the CJ43 can be shaped which delivers operational benefits to owners and operators in terms of lower OPEX and higher operational flexibility.
Full Waveform Inversion With Extrapolated Low Frequency Data
Authors: Li Yunyue Elita , Demanet Laurent
Published: March 2016

Low frequency data are crucial for the success of full waveform inversion (FWI) because it defines the low wavenumber component of the velocity model and determines the kinemat- ics of the seismic waves at higher frequencies. When low frequency data are missing, FWI with inaccurate starting models suffers severely from cycle skipping and yields erroneous inversion results. However, acquiring low frequency data from the field is a challenging and expensive task. In this paper, we explore the possibilities of synthesizing low frequencies from high frequency data. Low frequency extrapolation from the band-limited recordings is feasible by first separating the seismic record into individual events and extrapolating their frequency content to a lower frequency band based on the nondispersive assumption. The extrapolated low frequency data are reasonable approximations to the true low frequency data, with higher fidelity in phase than in amplitude. To demonstrate the reliability of the extrapolated low frequencies for FWI, we initialize FWI at low frequencies using the extrapolated phase information. The resulting low wavenumber models are then used to initialize full waveform inversion at higher frequencies. We demonstrate that FWI with extrapolated low frequency data produces reasonable estimations of the low wavenumber velocity model, which further help FWI escape the local minima.
Application of VTI Fast Marching Eikonal Solver to Improve Seismic Imaging
Authors: Alashloo S. Y. M. , Ghosh D. , Bashir Y.
Published: March 2016

Sedimentary layers in the Earth's subsurface result in seismic anisotropy which makes the wave velocity dependent to the propagation angle. This phenomenon causes complexities and errors in seismic imaging such as mispositioning of migrated events. One of the challenging issues in seismic imaging is the computation of seismic wave traveltime from source to receiver via the reflection point. A powerful method to compute traveltime is applying finite difference to solve the eikonal equation. In this study, we employ a fast marching eikonal solver in isotropic and VTI concept to obtain the seismic traveltime required for Kirchhoff depth migration algorithm. Rather than using elliptical eikonal equation which is commonly used in industry, we consider an anelliptic approximation since it is more realistic and accurate. Comparing the contours of isotropic and VTI traveltimes demonstrates a considerable lateral difference of wavefronts for both conditions. After Kirchhoff imaging, results show that the VTI imaging algorithm generates images with higher resolution than the isotropic one specifically in deeper parts where reflectors are more continuous and their patterns are more clear and traceable.
Single-Trip Abandonment Approach
Authors: Denmon Michael , Harive Kevin , Irvine Bruce
Published: March 2016

As the number of mature wells that are no longer economically viable increases, so does the need for effective well abandonment processes that meet stringent environmental and regulatory conditions. Because of varying well configurations and types, a unique or more tailored engineering approach is required to meet plug and abandonment governmental requirements, as well as operator-specific objectives for varying well designs. Through proper planning and design, this method also decreases operational and health, safety, and environmental (HSE) risks for a variety of challenging scenarios. This paper presents case histories of the successful use of a single-trip abandonment approach that saves time for the producers by addressing specific well types by simplifying the abandonment process in an economical and flexible manner through engineering planning and shaped-charge performance design.

The single-trip abandonment approach can drastically reduce associated costs common in well abandonment campaigns, including rig time and support services that are involved in making multiple trips in and out of the well. With an average rig rate of USD 500,000 per day for floaters, USD 100,000 per day for jackups, and USD 60,000 per day for barges (Rigzone 2015), any reduction in rig time exposure can be beneficial to the producer. By providing a method of successfully abandoning a well in one trip, as opposed to separate trips involving the cutting and removal of casing strings, the single-trip well abandonment approach allows producers to successfully plug and then spot cement in a combined action, permitting an expedited well abandonment process.

Through extensive testing and development of both tool technology and shaped-charge design, the single-trip well abandonment approach has proven to be a versatile and an effective system for a variety of well abandonment scenarios. Providing flexibility in operational capabilities for abandoning a well, squeezing off zones, providing limited casing entry, and allowing annular cement squeezing for remedial work, the single-trip abandonment approach has proven to be reliable and efficient, particularly in operations in the AsiaPac region. Using the engineering aspects of advanced tubing-conveyed perforating (TCP) design and capabilities as a building block in the single-trip system allowed for the successful implementation of required abandonment procedures while also providing the capability to be deployed in a variety of casing sizes, weights, and wellbore conditions.

This paper provides an in-depth study of the technical design, advanced modeling, multiconditional testing, and shaped-charge optimization of the systems for the single-trip abandonment approach. Additionally, the paper provides beneficial information that could be applied to well abandonment projects around the world.
Behind Casing Inspection Using Active Gamma-Gamma Technique
Authors: Hu Yike , Guo Weijun
Published: March 2016

During the completion of well drilling, cement is pumped into the annulus behind the casing to provide zonal isolation and a pressure barrier. The cement integrity inside the annulus is crucial for environmental and safety concerns. This paper describes a subsurface evaluation technique to evaluate the cement integrity behind the casing using an active gamma-gamma technique.

The target was a layered structure consisting of single or multiple layers of casing, cement in the annulus, and formation. The tool in use includes a radioactive gamma source and a gamma ray detector, which is designed to be sensitive only to the annular space away from the inner casing. Monte Carlo N-particle (MCNP) simulation based on high-energy photons transport was conducted to simulate the energy spectrum that would be measured by the gamma ray detector. Cement channels were represented by the void located in the annulus, which is characterized in volumetric terms and the localized area coverage of the voids. The detector responses change with different cement integrities. There are two attributes describing the gamma ray spectrum: count rates (CR) ratio and dipping point value. Through extensive computer modeling, the correlation between cement integrity and spectrum information was established, which are in terms used when generating equal CR-ratio curve and equal-dipping point curves. When investigating cement of unknown integrity, its gamma ray response is recorded by the detector and processed by algorithms. The dipping point value (Edip) and count rates ratio (CRratio) can be computed from the as-recorded gamma ray spectrum, and a volume-position chart can be generated in which the equal CR-ratio curve and equal-dipping point curve are plotted. The cement integrity information, the amount and the position of the void, are found simultaneously as the intersection of those two curves.

As compared to the conventional acoustic methods used in cement evaluation, this paper proposes an evaluation method using nuclear technology. The new method provides a data processing methodology to determine the void amount and position inside the cement, which could be used to image the void channel inside the cement.
Dry Tree Semisubmersible for Cost-Effective Deepwater Development
Authors: Tan J. H. , Kiprawi F. , Teng Y. , Kyoung J. , O'Sullivan J. F. , Nazri J. A.
Published: March 2016

Dry tree floating platforms for deepwater offshore developments are typically Spars and Tension Leg Platforms (TLPs). All production semisubmersibles in operation support only wet tree systems because the hull motions are not sufficiently small to allow the use of riser tensioning systems which connect vertical production risers from the subsea wells directly to the topsides. The wet tree semisubmersible designs can potentially be improved for dry tree applications with reduced heave motions. The advantages of dry tree semisubmersibles for deepwater development are presented in this paper with focus on the hull global performance and the cost benefits.

This paper presents a dry tree semisubmersible design with low heave motion and reduced vortex-induced-motion (VIM), hence named Heave and VIM Suppressed (HVS) semisubmersible. A case study of the HVS semisubmersible is performed for the dry tree application to support a relatively small topsides payload of 7,000 MT and five top tensioned risers (TTRs) in benign South East Asian environment. Through numerical simulations using Computational Fluid Dynamics (CFD) and conventional motion analysis based on potential flow theory, the hull global performance and maximum riser tensioner stroke range are provided. The stability analysis results for intact and damaged conditions are presented. The constructability and stability in pre-service conditions are briefly discussed to address the practical application of this hull with respect to cost effectiveness.

The results demonstrate technical readiness of this hull design by showing its ability in supporting dry tree systems with field proven riser tensioners and its superior stability for drilling operations. The application of this dry tree semisubmersible is technically feasible today in mild-to-moderate environmental conditions and thus it is an attractive option for new deepwater development with potential cost benefits.
Perforating the Largest High-Pressure Wells in the Gulf of Mexico
Authors: Brinsden M. , Gavric Z. , Le C. , Baumann C. , Smart M. , Stulb C.
Published: March 2016

The largest deepwater wells in the Gulf of Mexico have been drilled in the Lower Tertiary play. Most of these wells are completed with single-trip multizone systems have gross perforated lengths exceeding 1,500 ft. The main difficulty in perforating these wells is the ~20,000 psi high-pressure environment. Under these conditions, the challenges include creating sufficiently large entrance holes in the casing, minimizing the high-risk of equipment damage due to gunshock, and reducing the amount of perforating debris created.

Perforating several intervals in a single run is required to complement single-trip multizone systems. Perforating all zones simultaneously in a single trip saves time and reduces risk when compared with stacked frac-pack completions requiring multiple trips for each zone. Safety and cost reduction are extremely important in deepwater operations. Risk control is very important because gunshock and/or debris problems can lead to multimillion dollar losses in nonproductive time, and in extreme cases, gunshock problems can lead to lost wells.

To undertake these challenges, a new Low Perforating Shock and Debris (LPSD) gun system was used. In comparison with standard high-pressure guns, the LPSD gun system produces much less gunshock and negligible amounts of debris; thus, minimizing gunshock risk and reducing cleanup runs typically needed to recover perforating debris. LPSD guns produce negligible amounts of debris because LPSD guns retain all the metallic components inside the guns, including the shaped charge cases, which remain virtually intact inside of the guns. A key element in planning these perforating jobs is gunshock prediction to evaluate if the equipment will be able to withstand the transient loads produced by the perforating guns. The gunshock prediction process is described in detail in this paper.

For a typical 4- to 6-zone 1,500 ft gross length perforating job, the time needed from picking up the first gun to laying out the last gun averages 84 hours. All zones are simultaneously perforated, which eliminates at least three perforating runs per well, saving approximately 9.2 days per well while minimizing personnel exposure. By perforating the largest deepwater high-pressure wells in the Gulf of Mexico's Lower-Tertiary play with LPSD guns, we minimized personnel exposure, minimized debris and reduced execution time up to 72%.
Research of Improvement and Optimization of Critical Flow Rate Model in Condensate Gas Well
Authors: Zhou C. , Wu X. , Li H. , Tang J. , Liu X.
Published: March 2016

Critical flow rate models are widely used for liquid loading prediction in gas wells, take Turner's model as representative, but these models only analyze critical flow rate under wellhead or bottom hole condition, and take surface tension as constant, which results in a relatively large deviation between prediction result and actual liquid loading condition in condensate gas wells. In order to increase precision of liquid loading prediction, critical flow rate models are improved, aiming at solving above-mentioned problems. Different distribution of critical flow rate and surface tension along wellbore are considered, and the largest value of critical flow rate is taken as criterion of liquid loading condition, surface tensions under different temperature and pressure conditions are also calculated. Besides, on the basis of analyzing temperature and pressure distribution in dry gas wellbore by using temperature and pressure coupling method, a reasonable temperature and pressure coupling calculation model for condensate gas well is established, which considers the actual situation that both condensate and formation water exist in wellbore and revises relative density and flow rate of gas accordingly. Through verification by field case, it can be seen that precision of liquid loading prediction of improved critical flow rates models increases compared to that of original models, amongst which the precision of and the increased range of precision of liquid loading prediction of improved Li Min's model is highest. Therefore, the improved Li Min's model is the most suitable model for liquid loading prediction in condensate gas well.
Errors Due to Use of the AGA8 Equation of State Outside of Its Range of Validity
Authors: Glen N. F. , Mills D. , Griffin D. , Fosse S.
Published: March 2016

For many years the AGA 8 method has been the basis for all fluid property calculations related to natural gas supply, and forms an integral part of the measurement infrastructure throughout the world. However, application outside its valid range has the potential to cause significant errors. Case studies are presented that show the potential errors in density and compressibility, and resultant financial exposure, when using the AGA 8 method outside its range of viability.

If all the components are within the specified composition ranges for pipeline quality gas, densities calculated using the AGA 8 method are claimed to have an uncertainty of 0.1 % (at k=2) for temperatures between -10 and 65°C at pressures up to 120 bar(a). However, for mixtures with components in the extended composition range and / or at temperatures and pressures outside the standard limits, the uncertainty increases to between 0.2 and 0.5 % (at k=2) and is effectively indeterminate for compositions outside the extended range of applicability. Comparison with values calculated using the GERG-2008 method generally confirms these claims. However, even for compositions that are within the extended AGA 8 range, the differences can exceed 1 % and the effect of ignoring pseudo-components can cause differences of over 5 %. Given the known limitations of the AGA 8 method and the lack of clarity of the likely uncertainties in calculated densities and compressibilities when used in its extended range, the use of an alternative method would be preferable. Although the GERG-2008 method overcomes some of the limitations of the AGA 8 method, there still remains the problem of ensuring that all the components in the gas stream are measured.

By raising awareness of the limitations of calculating gas properties from composition, this work will help metering system designers, operators and regulators understand the issues that must be addressed when dealing with gas fields whose compositions are outside the pipeline quality gas specification required by the AGA 8 method, as the potential financial exposure can run to hundreds of millions of dollars per annum for a region such as the North Sea.
Pipeline Design Philosophy and Standards – A comparative Study and Recommendations
Authors: Singh Nawin , Nair Sajith
Published: March 2016

The most common method to transport oil and gas within the energy industry is through the pipeline transmission system. However, the pipeline system is very expensive, greatly on account of material and construction costs. One of the key decisive factors for a pipeline project is its capital expenditure (CAPEX). The material cost is primarily driven by "linepipe cost", which is a function of pipeline size and thickness. Several pipeline design standards are followed worldwide based on either the Working Stress Design (WSD) or the Load and Resistance Factor Design (LRFD) approach.

The aim of this paper is to present a comparative study and arrive at recommendations to optimize the material cost of linepipe, through a rational selection of the governing design code for pipelines, design philosophy and material grade. Hence, it is expected that the pipeline industry can benefit, particularly during the initial feasibility stage of evaluating the capital expenditure of a pipeline project.

As the pipeline diameter and operating parameters are fixed in line with process requirements, for purposes of mechanical design, wall thickness will be the governing cost parameter to be assessed. There are broadly two methods of design being followed in the industry to calculate the wall thickness based on pressure containment criteria i.e. WSD (stress criteria) or limit state. Traditionally, pipeline wall thickness is based on WSD, with the allowable design stress considered as a prescribed fraction of Specified Minimum Yield Strength (SMYS). However, there is inherent conservatism in the allowable stress method as only a certain fraction of material strength has been factored.

A recognition of this conservatism by the industry resulted in the limit state approach. A detailed comparison has been performed of available international design standards and the approach followed worldwide to develop the matrix and perform the parametric study. Literature review and parametric analysis indicates that linepipe material cost can be optimized upto 25%. To substantiate the findings, a case study for a typical pipeline project in the Middle East has been performed. FEM tool (e.g. ABAQUS) has been used to ascertain the stress and strain level.

The paper deliberates on the design code, design method and linepipe material and provides recommendations on the judicious selection of these parameters which can ultimately lead to optimum CAPEX. Results of the case study indicate that opportunities exist to optimize the material cost up to 15%.
Successful Tight Gas Development Practice in Ordos Basin of China
Authors: Zhang Xiangning , Zhang Minglu , Ge Chunmei , Deng Huaiqun , Wang Hongyu , Gong Bentao , Zhang Xiaofeng
Published: March 2016

Tight gas is an important resource for PetroChina's foreign cooperation business. PetroChina has cooperated with Shell and TOTAL in tight gas E&P in Ordos basin for years and has made great achievements. It was proved through years of exploration that sets of reservoirs occurred in the Perm-Carb system of the Ordos basin. Benxi, Taiyuan and Lower Shanxi formation are accumulated in marine environment and characterized by sandstones encased in mudstones, while the Upper Shanxi, Shihezi and Shiqianfeng strata are the continental deposits as the favorable targets in the basin.

CB is a cooperation project with Shell in northern Ordos basin. The Permian Shanxi tight gas interval was its target reservoir. CB is the first project deploying dual-lateral horizontal wells to explore the low permeability massive gas field in China and achieved big success. By far, the project has maintained annual production on a high level for 8 years. The second phase appraisal was initiated in 2013 to explore the secondary reservoirs. Recent testing result has seen a good indication and will be very helpful to raise total output to a new level. South Sulige gas field is located in the northwestern Ordos basin and is a project cooperated with TOTAL. To meet the challenges of poor lateral continuity and low reserve richness, an integrated new approach, such as reservoir prediction from 3D seismic Poisson ratio, "chessboard" well patterns from pad development, factory mode drilling and completion operations, were employed which effectively improved well performance and operational efficiency. PetroChina also initiated a joint study with ExxonMobil in Changdong area. The reserves were classified and individual well EURs were estimated by comparing with the U.S. Piceance basin and tight gas E&P practices in Ordos basin. The effective recovery of marginal pay sands will be crucial to the economic.

Total gas consumption in China grew by 7.4% and gas production grew by 6.1% in 2014. Being the largest O&G supplier, PetroChina produced 74.4% of the total national output in 2014. Tight gas accounted for 28% of total annual gas production in PetroChina. Annual natural gas production from foreign cooperation projects reached 6.55 bcm with more than 82% from tight gas reservoirs. Ordos basin, Sichuan basin and Tarim basin are all rich of tight gas resources. Foreign cooperation in tight gas resources in China is enjoying a favorable development circumstances and embracing its bright future.
The Production Benefits of Effective Well Integrity Management
Authors: Smith C. J. B. , Smith L. M. , Spowage A. C.
Published: March 2016

Effective well integrity management (WIM), properly implemented, achieves much more than its core aim of "reducing the risk of uncontrolled release of well fluids to the environment". Wells with ineffectively managed integrity issues result in significant and avoidable levels of well shut-ins and expensive workovers. State-of-the-art WIM software enables evaluation of well data in real-time to identify symptoms of developing issues, and by so doing, also enables proactive steps to be taken to prevent. The outcome is that the need for shut-in or other remedial action is reduced and in some cases sufficient evidence can be provided to confirm that the well is safe to continue in operation.

The same WIM software can also use a real-time risk evaluation to identify the most critical wells requiring specific attention, and in so doing prevent the need for shut-in, or defer intervention safely. The net outcome is that support is given for optimal, right-time decision making – more wells are available for production, risks are minimized (by mitigating problems in the wells with highest risk), and costs are kept to a minimum by prioritizing well activities. Overall production rates are significantly enhanced and overall costs are reduced.

This paper uses a series of examples of the common types of well integrity (WI) issue that can impact production to discuss how the above improvements can be realized. The examples covered in the body of the paper are: sustained annulus pressure, tubing corrosion and scaling. WI issues are also indicators of potentially disruptive production problems in the event of a leak or blow-out. While these risks cannot be fully overcome, they can be mitigated with comprehensive WIM. An observation is made that many WI issues go undiagnosed or undetected and this paper focuses on the importance of data as the input to drive effective monitoring. WI issues have significant potential impacts on production and cannot be treated in isolation. Advanced WIM technology enables the identification and diagnosis of integrity problems and must be considered for production optimization and cost reduction initiatives to be effective.
Unified Thermodynamics and Life of Field in Modelling Complex Upstream Facilities
Authors: Lam Ka-Mun , Zhang Xiaohong , Watson Martin J. , Zhu Wenting
Published: March 2016

Among the hidden and critical challenges in the process modelling of upstream projects are the limitations of compositional capabilities in Integrated Production Modelling (IPM) simulations comprising of complex processing facilities and the inadequacy of steady state and transient state simulations to represent the facilities operability across design life. These challenges become more crucial as future developments are moving to deeper waters and dirtier hydrocarbons.

By implementing Unified Thermodynamics with a single fluid model, MultiflashTM Cubic Plus Association (MF-CPA), all the fluid phases as well as the solid phases such as gas hydrates, waxes, asphaltenes and mercury partitioning can be modelled simultaneously within the IPM itself. The Life of Field (LOF) method enables the understanding of how the different parts of the system in the IPM interact when concepts are changed. The combination of both Unified Thermodynamics and LOF enables front end and operational studies to be performed accurately and efficiently.

The case study shows the impact of two different processing facilities' arrival pressures on the production profile, project scheduling, material selection, gas hydrate formation risk and inhibition requirements, gas compression and turbine performance and sizing, mercury partitioning and CO2 production. By anticipating these changes more accurately, underpinned by MF-CPA, overly conservative equipment sizing can be avoided to reduce project CAPEX and improve asset efficiency across field life. This paper demonstrates the integrated application of process simulation and flow assurance tools from wellbore to customer to optimise project workflows and decision making for optimised investment.
Overpressure Protection Workflow to Address Pipeline Integrity Using Multiphase Dynamic Simulation
Authors: Govindan Gunasekar , Shaharun Azwan
Published: March 2016

This paper proposes a work flow to address the challenges of over pressure in pipelines using the industry standard multiphase transient simulator. Electric submersible pumps (ESPs) are commonly used to increase the productivity of the wells, which, in turn, will generate higher shutoff pressure in the event of sudden wellhead and subsea line valve closures. The topside piping or the subsea line must be protected from overpressure during valve closures with the ESP still in running condition, so that the pressure does not reach beyond the maximum allowable operating pressure (MAOP) of the pipeline. Hence, it is critical to estimate the peak pressure surge, time to reach peak pressure, emergency shutdown (ESD) set point, and high-integrity pressure-protection system (HIPPS) initiation time.

The topside piping is normally designed with an MAOP significantly lower than the ESP shutoff pressure. In the event of sudden closure of wellhead platform valves or the valves located at the end of a subsea pipeline, the pipeline will be pressurized equivalent to the shutoff pressure of the ESP. In general, to protect the topside piping, several layers of protection are provided, with ESD and HIPPS being very common. The proposed workflow demonstrates the use of a multiphase transient simulator to estimate the peak pressure reached upon wellhead valve closure and the time required to reach the peak pressure for different scenarios so that the ESD initiation set point can be selected optimally. Once the ESD sequence activates, the pressure response in the piping during shutdown also can be estimated in an accurate manner. Further, in case the ESD system fails to respond, the workflow identifies the time to activate the HIPPS system, which will be based on the MAOP and time needed for HIPPS to activate. The workflow has been used extensively in major oil projects with ESP-operated wells to address their ESD and HIPPS activation set-point selection as a part of HAZOP closeout.

The workflow underscores the role of transient simulations in predicting the peak pressures, timing, and optimal ESD and HIPPS activation time to protect wellhead piping, thereby providing critical information to address piping/pipeline integrity challenges.
Coring Parameter Optimisation - The Secret to Long Carbonate Cores
Authors: Keith Cheong Ing , Safari Abasad , Aik Khaw Loong , Thanasekaran Maniam , Farouk Mohamed
Published: March 2016

Drilling in carbonate reservoirs are challenging in many ways let alone coring. Recently PETRONAS Carigali Sdn. Bhd. managed to successfully core 224m of carbonate formation in a reservoir which contains 70% Carbon Dioxide (CO2) and 70 ppm Hydrogen Sulphide (H2S). This well is located in the western part of the Luconia field offshore Sarawak in Malaysia.

Core jamming is one of the biggest culprits of failure in obtaining good core recovery especially in carbonate formations. This is due to the highly vugular nature of carbonate formations which also causes losses of drilling fluid. To add to the challenge in this particular field, the carbonates here vary in their degree of porosity according to depth which means a variation of matrix compactness. This causes drilling breaks and can pose a challenge for coring if not understood properly. Core jamming in loose and interbedded carbonate reservoir pay zones has been a frequent occurrence in the wells drilled in these blocks which motivated the drilling team to optimize certain technical aspects of coring such as selectingthe most appropriate core head, bottom hole assembly (BHA), coring parameters and mud system additive chemicals to prevent jamming from happening.

The purpose of this paper is to share PETRONAS' experience of using optimized coring parameters to yield a high percentage of carbonate core recovery. The main advantage of these optimizations is to prevent core jamming problems in the carbonate reservoir in order to obtain good core recovery within the stipulated time. The paper discusses PETRONAS' experience of coring parameters optimization as well as proper coring equipment selection for successful coring in a highly sour carbonate reservoir. On the basis of offset wells and lesson learnt, these optimizations were evaluated and applied successfully to cut the 224m of core in the carbonate reservoir. Several core runs prompted realization that jamming was prone when certain parameters were not optimized hence requiring changes in parameters as well as core bits. Core bit selection and cutter size play an important role in ensuring a successful core run. The understanding of the carbonate reservoir geology is also crucial in order to apply the right parameters to cut the core successfully.

These optimizations proved its worth as it helped PETRONAS to obtain good core recovery and to prevent unnecessary trips that will result in additional time and cost to the operator. This unique PETRONAS experience will help make coring more efficient coupled with good recovery in some of the most challenging carbonate formations.
Structures Deepwater Installation Challenges – North West Shelf, Australia
Authors: Broadway Trent , Tachoires Vincent
Published: March 2016

Today's Oil and Gas developments continue to push the envelope with regard to the increasing weight and size of subsea structures and installation water depth. This paper provides an insight into the challenges encountered and overcome to install 20 subsea structures, some close to 1000Te in weight, and in water depths of up to 1350 meters. The work was for the Chevron-operated Gorgon Project in Western Australia.
Improving the Operational Performance and Reliability of Casing and Tubing With the Use of Dope-Free Connections
Authors: Emiliano Actis Goretta , Mustaffa Merliahmad
Published: March 2016

This paper describes how the adoption of Dope-Free connections is simplifying and improving the operational performance of Casing and Tubing operations and a methodology to analyze the efficiency of running operations.

Dope-Free connections are tubular connections with a multifunctional dry coating applied to their threads and seal areas in a controlled industrial environment that eliminates the need for storage and running thread compounds during the tubulars' full life. The impact of Dope-Free connection in an operation can be easily quantified by using readily available data. This is performed by analyzing the connection make-up charts (torque vs turns) of Dope-Free and standard connections from running operations.

Most connection problems and failed installations occur at the well site, driven by inexperience personnel, improper execution, and/or wrong interpretation of the make-ups caused by variability on the behavior of thread dopes under different environments. Removing the thread compound from the connection reduces the risk by having a lower possibility of miscommunications, connection damage, improper procedures, and applying the wrong dope. Although initially driven by environmental issues, the elimination of storage and running compounds from Casing and Tubing strings brings an array of benefits, from improved operational performance and HSE to well productivity. Operators experiences, after a short learning curve, showed great reductions in installation time, reduction on connections re-make ups and rejects along with improvement on workers' Health & Safety conditions by eliminating unsafe tasks and creating cleaner work areas, and minimization of the environmental impact.

The rig time saved due to less remake-ups and rejects of a Dope-Free connections running compared to standard connections can be easily converted to economic savings. This is especially important for offshore operations where high daily rate cost rigs are used.
Integrated Gas Blending and Optimisation
Authors: Muhamad Sori Zohairen Bin , Hashim Sharipuddin Bin , Chun Leo Andy Kee , Orenstein Horia
Published: March 2016

BIG DATA and GAS NETWORK MANAGEMENT: two extremely different terminologies used in the past in extremely different contexts. This paper details the effort and success by Malaysia Petroleum Management (MPM), PETRONAS. This initiative was supported by SAS Institute and Protechnology/Netgas. It is to merge the 2 worlds and handle the current challenges met in the management of complex upstream gas pipeline networks with an innovative and effective solution based on the principles of big data analytics.

The starting point was for us to gather the requirement to respond quickly and accurately to demand volatility and changing network operation conditions, while complying with the tripartite commercial agreements between PETRONAS, our natural gas customers and our Petroleum Arrangement Contractors (PACs). A software solution was developed to put the gas flow process, with its fluid- and thermodynamic rules, in the center of the operational process of gas gathering and blending, as well as the management of related commercial transactions and pipeline network operation management. The solution optimizes the volumetric transactions and ensures the delivery quality of the natural gas, supplied from different platforms at different qualities, while ensuring operational controllability with precise operator guidelines. It ensures so the highest operational regularity and planning flexibility. The modular software solution brings a couple of important innovations like dynamic calculus-numerical modeling of a full pipeline network, reverse simulation which optimizes automatically the supply and controls to meet the demand, integration of the commercial volumetric logic with the operational fluid- and thermodynamic, workflow automation and data and information integration. Supporting existing business processes, like planning, scheduling and operational monitoring, the fast staged implementation approach and the ease of use round up the benefits of this innovative solution with low entry barrier.
Low Pressure Enhanced Liquid Recovery System LP-ERS
Authors: Jothy A. , Thiruthonder H.
Published: March 2016

The LP-ERS process is suitable for implementation on marginal and stranded crude and associated gas producing fields where associated gas is used as fuel and/or flared. Whilst flaring of associated gas is not recommended, in many instances this is unavoidable due to various techno-commercial considerations. Crude and associated gas production facilities typically receive production fluids from wells at relatively low pressures, ranging from 5 barg to 20 barg. At these pressures, there would be significant quantities of C4+ components that can be extracted as condensates and stabilized with the crude. However, conventional enhanced recovery systems currently available are bulky and costly, resulting in these enhanced recovery systems not being implemented for marginal and stranded developments.

The LP-ERS is a proprietary process, particularly developed to address the abovementioned issues, to extract condensates (C4+ components) from low pressure associated gas in a cost effective manner, without the need for bulky compression, refrigeration and dehydration facilities that are typically required for conventional enhanced recovery systems. Apart from increasing revenue due to increased volume of stabilized crude production which is generally in the range of 5% to 25% (depending on wellstream fluid GOR, etc.), the implementation of the system will also significantly reduce greenhouse gas emissions (by approximately 20%) and improve the quality of the bulk stabilized crude oil produced.