bluuebunny/crossref_metadata_2025 huggingface dataset:
Silica-Templated Synthesis of Novel Zinc-DTPMP Nanoparticles, Their Transport in Carbonate and Sandstone Porous Media and Scale Inhibition
Authors: Zhang Ping , Kan Amy T. , Fan Chunfang , Work Sarah N. , Yu Jie , Lu Haiping , Al-Saiari Hamad A. , Tomson Mason B.
Published: July 2010

In this study, a silica templated synthesis route was adopted for fabrication of zinc-phosphonate nanoparticles to expand their use in the delivery of phosphonate inhibitors into formation core materials for scale control. Transition divalent metal Zn2+ was chosen due to its ability to significantly increase inhibitor retention and effectiveness. Zinc chloride was first adsorbed onto the surface of 22 nm silica particles, followed by gradual addition of diethylenetriaminepentakis (methylenephosphonic acid) (DTPMP) to form nanometer sized particles in the presence of sodium dodecylbenzene sulfonate (SDBS) surfactant. The physical and chemical properties of the synthesized Si-Zn-DTPMP nanoparticle slurry (nanofluid) have been carefully evaluated. The nanofluid was stable at 70°C in 1 % KCl at pH 6.7 for over 12 hours. The transport of the synthesized nanofluid through calcite and sandstone formation porous media has been investigated using column breakthrough experiments and modeled with a 1-D advection-dispersion equation. The nanofluid was transportable through these media and near total breakthrough could be obtained by pre-flushing the media with an anionic SDBS surfactant solution. The diafiltration experiment was designated to transform the nanoslurry into a less soluble phase, and such materials demonstrated a much longer inhibitor lifetime compared to the untreated ones. The long-term flow back performance of the fabricated nanofluid was examined via a laboratory squeeze simulation test where the nanoparticles gradually returned phosphonate inhibitors in the flow back brine solution, and the normalized return volume was comparable to conventional squeeze treatment.
Corrosion Management of Aging Assets from the New Operator's Perspective
Authors: Marsh Z. , Munday M.
Published: July 2010

Many assets in the UK sector of the North Sea are approaching or have passed the intended design life. The general decline for of many mature assets has been reversed as new operators invest significantly and target increased asset life when compared to the former owners. This poses a number of challenges for continued corrosion control. Some mature assets have seen multiple ownership transfers with repeat changes in corrosion management philosophies. For a mature asset historical records may be in various states of completeness. Operational conditions, likely to have changed radically since original design, may with investment be subject to increased requirements for gas lift, water injection and high water cuts. The new duty holder of a mature asset must take these factors into account when formulating their own corrosion management system. This publication examines the areas of concern to operators taking over ageing assets that are approaching or have exceeded design life. These include corrosion management, compatibility with increasing H2S levels (reservoir souring due to seawater breakthrough), corrosion mitigation, materials selection and fabric maintenance and repair. It discusses effective, but cost efficient methodologies that reflects the required future asset life.
The First Through-Tubing Capillary String Installation in the UK Sector of the North Sea
Authors: Bremner B. , Murphy L. M. , Affinito R. J. , Larnach A. , Sanders D. L. , Taggart M. J. , Willis M. J.
Published: July 2010

The Britannia field has been on production for approximately 10 years. Produced fluids are retrograde gas condensate with some associated water. In recent years, as the reservoir pressure has declined, some of the wells have entered a region where flow has become unstable due to the phenomenon of liquid loading. In a small number of cases the effects of liquid loading are so pronounced that the wells remain largely shut in and are not considered to be part of the “production pool”. In others a cyclic clean up program is employed which involves routing the wells periodically through the test separator at low pressure to unload the associated liquids.

In 2007 a Low Rate Well Strategy was developed in order to identify possible solutions to address this issue of liquid loading. One such strategy was that of continuous foam injection at or just above the producing interval. This chemical application works by lowering the minimum liquid unloading rate of an individual well, thus enhancing the ability of that well to lift liquids from the wellbore.

The method selected by Britannia to enable continuous injection of the chemical foamer was via a permanently installed thru- tubing capillary string. Capillary tubing is similar in appearance to coiled tubing. However it is much smaller in size, the outer diameters ranging from 1/4” to 5/8” and is more akin to the control line used to contain fluid for the operation of sub surface safety valves.

The process by which a suitable chemical foamer for Britannia was selected and tested, both from an effectiveness and compatibility standpoint, will be discussed.

The first operation to install a 3/8” capillary string on a Britannia well was successfully completed in May 2009. This was followed by a second installation in July 2009. The procedure included the installation of a modified tubing bonnet, which allows chemical injection at the wellhead, and deployment of a capillary tubing system which contains an integral sub surface safety valve. This system provides a flow path for produced fluids, and allows continuous injection of the chemical foamer from surface to the producing interval, whilst maintaining full well integrity.

This paper will discuss the first installations of this system in the UK sector of the North Sea. The planning and design activities, followed by the offshore implementation, will be described in detail. Candidate selection and a review of well performance, both pre and post capillary string installation, will also be included.

Whilst the “Wellhead Modification System” has been employed for the initial installations, simplified designs are being reviewed for future Britannia wells and these will also be discussed.
Coiled-Tubing Fracturing: An Operational Review of a 43-Stage Barnett Shale Stimulation
Authors: Castañeda Juan Carlos , Castro Luis , Craig Steven , Moore Christopher , Myatt James
Published: July 2010

Traditional multi-stage high rate fracture treatments have been used in many shale and conventional formations. These treatments typically rely on composite bridge or frac plugs, run on wireline to provide zonal isolation. In a typical frac treatment, rates of up to 100 bpm are normally divided between four to six pre-perforated clusters per stage. Typical spacings between clusters are 50 to 100 ft. In theory, fluid would divide equally between each perforated cluster, however that is an unlikely scenario since stimulation treatments will follow the path of least resistance. To improve production results, targeted fracturing operations are gaining in popularity in many formations.

Some targeted operations utilize abrasive perforating via coiled tubing (CT), followed by the fracture treatment down the annulus. The treatment flush is modified to include an underdisplaced dense slurry stage to act as the isolation mechanism. In vertical wells, proppant settles by gravity covering the recently treated interval. In horizontal wells however, a plug enhancement additive (PEA) can be used to achieve isolation, partially mitigating gravity effects. Moreover, instead of splitting flow between four to six clusters, most horizontal treatments target only one discreet cluster/zone at a time. Significant gains in fracture control are obtained with this method. Initial targeted operations were applied to 300 ft of frac spacing, thus reducing the number of stages per well when compared to the 50 to 100 ft cluster spacing on higher rate frac operations.

This paper describes one targeted operation in a horizontal well where the spacing was reduced to 60 ft. In all, forty-three stages were successfully stimulated using enhanced sand plugs for zonal isolation.
Tapered-OD Connection using a Spoolable Connector
Authors: Ehtesham M. A. , Zhong A. , Domann R. E.
Published: July 2010

The coiled-tubing (CT) industry has evolved from using smaller pipes with lower-grade materials to bigger pipes and high- strength materials. However, the offshore installations and equipment still need to catch up with increased weight and handling demands. A tapered outer-diameter (TOD) string is one solution that provides the benefits of larger string while keeping size and weight at manageable levels. This paper presents a study and analysis of using a spoolable connector (SC) to join strings of two different outer diameters (ODs).

A TOD string requires an 8- or 10-ft long “transition section” so that the string can pass through specially retrofitted injectors. The transition section is milled, from one diameter size to another, using a cold-working process. This transition section needs to be welded to the two strings and requires a manual butt weld. As an alternative, a transitional spoolable connector is being developed and virtually tested using finite element analysis (FEA), thus eliminating the need for a specially milled, butt-welded transition section.

One challenge with TOD-connection systems is that they tend to fail at the butt-weld between transition and core end of string. A 10-ft long SC was designed to transfer this high-strain area away from the transition where it would be less detrimental to fatigue life. SCs for regular pipes have been designed and tested in variety of sizes from 1.5- to 2.875-in. OD CT. The test data provided a base to compare the performance of this new transitional connector. Results from a 2- to 1.75-in. tapered OD string are presented. One complete bending event of a 20-ft long assembly was simulated on a drum using FEA, and results were compared with actual and virtual test data from pipe with SC and a TOD string with transition section.
High-Risk Coiled-Tubing Intervention Results in Substantial Savings
Authors: Thom F. N. , Taggart M. J. , Murdoch J. D. , Ewing B.
Published: July 2010

Shell U.K. Limited Teal P1 subsea well was completed in July 1996 with a peak flow rate of 40,000 bopd. During the completion phase there were a number of problems and failed attempts in setting the production packer, which subsequently resulted in debris in the wellbore. To prevent this debris damaging the turret assembly in the FPSO, a debris barrier, consisting of a perforated tail pipe and a 3 ½” bridge plug, was installed in the production tubing 50 ft below the TRSSSV. Problems with the TRSSSV and the subsea tree valves resulted in a completion workover being scheduled. Prior to pulling the production tubing, the A-annulus was pressurised to 3500 psi to reduce the differential pressure across the tubing. At 2850 psi there was a sudden loss in pressure indicating a leak in the outer casing string. The workover was suspended and the well left in a safe condition. Planning for a full abandonment was then implemented.

Two abandonment options were possible: remove the debris barrier and abandon the well using coiled tubing, or drill a secondary well which would intercept the reservoir section of Teal P1 allowing it to be isolated. The coiled tubing option was only given a 30% chance of success, but due to the potentially large cost saving if successful, this became the primary option. The main hazard in the coiled tubing intervention would be removing the 3 ½” bridge plug from the debris barrier which had been in place for over 12 years. To address this a number of onshore trials were carried out to determine if the plug could be milled if fishing was not achievable.

After a total of 52 coiled tubing runs with a variety of customised BHA's, the requirements of the coiled tubing intervention were met allowing full abandonment of the reservoir. This paper discusses the well history, requirements of the coiled tubing intervention, the onshore trials and the offshore operation.
Snubbing Units Used Effectively in Well Control Recovery Efforts
Authors: Wehrenberg S. R. , Baxter O.
Published: July 2010

This paper will discuss the use and advantages of employing snubbing units during and after well control operations. The benefits of snubbing units compared to coiled tubing are widely known and generally accepted in the industry. During some well control operations the advantages a snubbing unit provides can positively impact the outcome of the well.

From its inception solely as a mechanism for handing tubulars during well control operations, snubbing has evolved into a highly versatile technology, offering myriad operational, economic and HSE benefits. To illustrate the versatility of new generation snubbing technology in a variety of well control situations, the authors will present case studies of a number of diverse applications.

The paper is intended to educate operators and service contractors alike by sharing experiences, lessons learned and demonstrating the effectiveness of snubbing units in a variety of hostile well control environments, including its use with gunk squeezes.
The Design and Application of Snubbing Units for an HP/HT Environment
Authors: Wehrenberg Steve
Published: July 2010

Typically, in a high-pressure, high-temperature (HPHT) well, operators incorporate heavy workover and drilling fluids to provide a barrier to control the pressure. Often, the end result is formation damage, loss of un-recoverable fluids and appreciable increases in workover and completion costs. To help alleviate this and other problems in challenging environments, the use of snubbing units has come into vogue as a viable solution to the obstacles and resulting problems associated with drilling, workover and completion operations in an HPHT environment. The technology has evolved to the point that it can efficiently perform any function required of a conventional drilling rig. Recent experiences in the Haynesville and other un-conventional shale gas plays onshore the US have demonstrated the advantages of snubbing units in a variety of applications, including those involving hostile HPHT environments.

This paper discusses the evolution, design and application of snubbing units for HPHT applications with particular emphasis on the pre-well planning involved. To illustrate the operational, economic and environmental advantages of snubbing technology compared to coiled tubing and other more conventional approaches, the authors will present operational data from a recent HPHT well, along with a discussion on the ideal scenarios where snubbing technology should be considered.

Designed to provide insight for both operators and service companies, the paper will share experiences and lessons learned to demonstrate the effectiveness of snubbing units in an HPHT wellbore.
Phase Stability of Calcium Sulfate in the System NaCl/monoethylene glycol/water
Authors: Lu Haiping , Kan Amy T. , Zhang Ping , Yu Jie , Fan Chunfang , Tomson Mason B.
Published: July 2010

Calcium sulfate is one of the dominant scales in the oil field. At high temperatures, hemihydrate (CaSO4·0.5H2O) and anhydrite (CaSO4) are the predominant sulfate scales formed, while gypsum (CaSO4·H2O) scale may form at low temperature during offshore production with long tie-back particularly if hydrate inhibitors are used. The prediction and prevention of calcium sulfate scales require accurate knowledge of the solubility and phase behavior of the three major phases of calcium sulfates.

The phase behaviors of the different calcium sulfate phases are related to the supersaturation state, temperature, and fugacity of water. In this study, the effect of a common hydrate inhibitor, monoethylene glycol (MEG), on calcium sulfate solubility and phase behavior was investigated. Three approaches were taken to determine the kinetics of calcium sulfate phase transition at various temperatures, ionic strengths, and MEG concentrations: (1) Dissolution of gypsum as the starting material, (2) Dissolution of anhydrite as the starting material, (3) Precipitation of calcium sulfate by mixing calcium and sulfate containing solutions. The effect of scale inhibitors on phase transition was also evaluated. This study was run in NaCl/CaSO4/MEG/H2O solutions at 0–6 molal NaCl and 0–95 wt% MEG at 4–70°C. The calcium concentrations in liquid samples were analyzed by Inductively Coupled Plasma Atomic Emission Spectroscopy (ICP-AES) and EDTA (ethylenediamine tetraacetic acid) titration, and the morphology, phase composition and water content of solid samples were examined by Scanning Electron Microscopy (SEM), X-Ray Diffraction (XRD), and Thermogravimetric Analysis (TGA). Phase transition of gypsum to anhydrate was observed in the presence of high concentrations of NaCl and MEG, regardless of the experimental approach. The transition boundary of temperature and NaCl and MEG concentration can be estimated quantitatively from solubility and fugacity of water. The inhibition of hexamethylenediamine tera (Methylene Phosphonic acid) (HDTMP) was also tested by using precipitation method to investigate the precipitation kinetics of calcium sulfate.
A New Synthetic Polymer Provides Improved Drag Reduction in Coiled-Tubing Operations in North Louisiana
Authors: Fox K. B. , Bainum M. S.
Published: July 2010

A new friction reducer was tested in various fluids to measure its performance in both a small scale flow loop and a field- scale system. The friction reducer is a high molecular weight, synthetic polymer, which is compatible with many brines, including calcium chloride and calcium bromide, and is thermally stable. The friction pressure study utilized fresh water and several brines, including 7% KCl, 9.7 ppg NaCl and 11.4 ppg CaCl2. The fresh water systems were pumped through 1½ inch diameter coiled tubing and straight pipe. For the heavier brines, a small scale flow loop, consisting of ½ inch diameter coiled tubing and straight pipe was used. There was good correlation between the fresh water friction pressures measured in the small scale flow loop and full scale system for straight pipe. Drag reductions as high as 81% were achieved in the straight pipe, and as high as 69% in coiled tubing. The heavier brines generally required greater polymer loadings in order to achieve substantial drag reduction.

Field applications of the new polymer have been conducted in North Louisiana, in the Haynesville Shale. These treatments utilized 9.8 ppg produced brines, and were pumped through 17,000 feet of coiled tubing. The polymer was applied as a suspension in order to provide enhanced field mixing. The use of the new polymer produced significantly greater friction reduction than previous technology, and provided improved economics.
Capillary Trapping in Carbonate Rocks
Authors: Lamy Celine , Iglauer Stefan , Pentland Christopher H. , Blunt Martin J , Maitland Geoffrey
Published: July 2010

Carbonate reservoirs represent a possible geological storage option for carbon dioxide from anthropogenic sources. We conducted capillary trapping experiments on different carbonate rocks to assess their suitability for storage. We measured the trapped non-wetting phase saturation as a function of the initial non-wetting phase saturation and porosity. We used refined oil – with a density similar to that of supercritical CO2 – as the non-wetting phase and brine as the wetting phase. The experiments were performed at ambient temperature and slightly elevated pressures. Saturations were determined by mass and volume balance. We found that the trapped non-wetting phase saturation rises approximately linearly with initial saturation. The porosity was shown to have a significant effect on both initial saturation and residual saturation. The influence of effective stress was also investigated. It was shown that carbonates have significantly different stress behavior compared to sandstones. As the pressure of the non-wetting phase increases during primary drainage, the initial oil saturation increases to a maximum value and then decreases, as the fluid pressure affects the pore structure of the rock.
Accurate Fluid Interface Tracking of Interwell Tracer Flow by the Constrained Interpolation Profile Method
Authors: Goda T. , Sato K.
Published: July 2010

An accurate numerical technique to follow tracer movement between sink and source is an invaluable tool in evaluating reservoir formation from interwell tracer test data. Tracer flow in porous media is modeled by the convective-dispersive equation. In case of convection-dominance over dispersion, the interface between tracer slug and tracer-free fluid becomes sharp and most finite difference techniques tend to cause numerical diffusion or non-physical oscillation.

To overcome this difficulty, the constrained interpolation profile (CIP) method, a universal solver of hyperbolic equations, is employed for solving tracer flow problems in this study. In the CIP method, not only the tracer concentration but also its spatial gradients are simultaneously evaluated at each gridblock, so that more continuity conditions can be imposed to construct an interpolation function between neighboring gridblocks and the sharp interface can be tracked more accurately. The computation procedure is followed by a semi-Lagrangian scheme; the governing equations of both tracer concentration and its spatial gradients are decomposed into convective and non-convective phases. The convective phase is calculated by the CIP method, while the non-convective phase by the finite difference approximation.

For one-dimensional test problems, the numerical results using the CIP method are almost in complete agreement with the analytical solutions, which verifies the accuracy of the developed method. Also the verification of the developed method for two-dimensional computation is provided by comparing the numerical results with semi-analytical solutions obtained using the complex variable boundary element method. Furthermore, from the numerical results of various two-dimensional example problems, such as staggered/direct line drive pattern floodings and flows in heterogeneous permeability fields, the developed method is found to be of use for practical purposes.
Low-cost Monitoring of Inter-well Reservoir Communication Paths Through Correlations in Well Rate Fluctuations: Case Studies from Mature Fields in the North Sea
Authors: Heffer Kes , Greenhough John , Main Ian G , Zhang Xing , Hussein Assef Mohamad , Nasreldin Gaisoni , Koutsabeloulis Nick
Published: July 2010

A major key to rejuvenating mature oil and gas fields for improved recovery is the ability to characterize the reservoir between existing wells: currently practised methods for surveying inter-well properties are generally costly. A recent project has combined three technologies which utilize readily available fluid production histories to produce a process for identifying inter-well reservoir communications in producing oil or gas fields. Fluctuations in the well production and injection rate histories are analyzed in the context of coupled geomechanical-flow processes involving activated faults and fractures through (i) the Statistical Reservoir Model (SRM), (ii) conventional correlation analysis and a new technique for extracting rate diffusivity tensors, and (iii) coupled geomechechanical-flow modelling. These technologies have been applied to five oilfields located in the North Sea from the North Viking graben to the Central graben with the key results that (i) the general long-range nature of rate correlations is consistent with some dependence on hydro-mechanical changes near a critical point, and (ii) the patterns of orientational distributions of rate correlations from all five fields are consistent with induced shearing on faults or fractures as an inherent mechanism of reservoir communication. Identification of major reservoir pathways is of substantial advantage to efficiency in reservoir management, leading to benefit for practical issues of well placements and configurations, injectivities, productivities, sweep efficiencies, short-term and longer-term forecasting. In particular the techniques can be used in a time-lapse fashion in order to monitor changes in reservoir behaviour and provide real-time updating of reservoir models. Together, these techniques can directly assist rejuvenation of mature fields; additionally, albeit tentatively, the improved understanding of fundamental reservoir mechanisms can lead to better planning of ‘green’ fields.
Rapid Determination of MIC in Oil Production Facilities with a DNA-based Diagnostic Kit
Authors: Skovhus Torben Lund , Sørensen Ketil Bernt , Larsen Jan , Rasmussen Kim , Jensen Michael
Published: July 2010

The use of culture-based microbiological methods is slow and can only measure the few sulfate-reducing Bacteria (SRB) that can be cultivated. Faster and more accurate techniques for the diagnostics of microbiologically influenced corrosion (MIC) are therefore required.

This paper demonstrates the benefits of applying state-of-the-art molecular microbiology methods (MMM) to the identification and quantification of the microorganisms contributing to corrosion in oil production facilities. For quantification of troublesome microorganisms MMM can be applied directly to solid samples from the oil field without the need for culture media.

The corrosion mechanism was investigated in two different cases: (i) a piece of piping with high corrosion rates from the water outlet of a separator from the Halfdan oil field, and (ii) a similar piece of piping from the Dan oil field with much lower rates of corrosion. The chemical distribution of elements was analysed using X-ray diffraction and the levels of MIC causing microorganisms were determined with qPCR (a DNA-based quantification method).

The results showed that corrosion in the piping from Halfdan was caused by MIC. The results also showed that not only SRB were involved in the observed MIC. High numbers of sulfate-reducing prokaryotes (SRP) and methanogens were measured in material from the Halfdan separator with high corrosion rates. The methanogens were particular abundant close to the metal/scale interface. The data indicates that the high level of microorganisms in the Halfdan separator speeds up the corrosion process by efficiently consuming hydrogen released during dissolution of iron.

Finally, the paper discusses the strength of applying qPCR as a standardized, high-throughput routine monitoring tool for MIC diagnostics when developing more reliable integrity management programs in the future. This study has shown that the improved molecular microbiological approach to MIC is important when designing and testing remedial actions towards MIC in oil field systems.
A New Method for Forecasting Dynamic Reserve of Fractured Gas Well in Low-permeability and Tight Gas Reservoir
Authors: Ruilan Luo , Qun Lei , Yongxin Han , Jinde Feng , Chunhong Ma
Published: July 2010

Influenced by special geologic condition and stimulation, the production performance of low permeability and tight fractured gas well is obviously different from that of conventional gas well, such as longer unstable flow time, gas production with unit change in casing pressure, dynamic reserve and drainage area varying with production time, etc. So it is difficult to calculate reserve and drainage area accurately at early development stage. For these reasons, they bring great technical and economic challenges to the development of low permeability and tight gas reservoirs.

Properly recognizing the dynamic performance of fractured tight gas well and combined with modern gas production analysis technology, a new prediction chart of estimated reserve is established. This calculation utilized extended production data from several typical gas wells in Sulige gas field. Using early stage production data, the preditoin chart can provide estimations of gas reserve and drainage area of individual wells. Other parameters such as productivity scale, well pattern and spacing can also be included. This methodology can make prediction effectively with incremental production time. It is an excellent predictive guide to launch a development plan of the gas field.
Multi-Field Asset Integrated Optimization Benchmark
Authors: Rahmawati Silvya Dewi , Whitson Curtis Hays , Foss Bjarne , Kuntadi Arif
Published: July 2010

Integrated modeling of multi-field assets, from subsurface to market, is challenging due to the complexity of the problem. This paper is an extension of the SPE 121252, model based integration and optimization gas cycling benchmark [Juell, et al., 2009], extending two gas-condensate fields to two full-field multi-well models. Additionally, a full-field model is added to the Juell benchmark, introducing an oil field undergoing miscible WAG injection, where most data are taken from the SPE 5 Reservoir Simulation Comparative Project. All reservoir models are compositional, but using different EOS representations. A base case scenario is defined with fixed numbers and locations of producers and injectors.

A common field-wide surface processing facility is modeled with emphasis on water handling, NGL extraction, sales-gas spec, and gas reinjection. The surface process model interacts with the three reservoir models through two main mechanisms – (1) water- and gas-handling constraints, and (2) distribution of available produced gas for reinjection into the three reservoirs.

The field asset model provides long-term production forecasts of gas, oil, and NGL revenue. Cost functions are introduced for all major control variables (number of wells, surface facility selection and operating conditions, injection gas composition). Net present value is used as the target objective function.

This paper will evaluate optimal production strategies for the base case benchmark problem, using several key control variables and field operational constraints. Optimization performance will be tested with a few solver algorithms. The benchmark will be provided to the industry through application data files, network infrastructure, and results from our integrated optimization model.
Fluid Delumping Applied to the Goliat field: A Black-oil Model Coupled with a Process Design
Authors: Vignati Emanuele , Bonotto William , Cominelli Alberto , Stano Elena , Le Maitre Claire
Published: July 2010

It is a common practice to use a limited number of components to describe hydrocarbon fluids in reservoir simulation, even though process engineering needs a richer set of components to model the top-side separation process. This requires delumping of the well streams from reservoir models to meet the detailed description needed by the process engineers. We have tackled this problem on the reservoir model of the Goliat field, located in the south-western part of Barents Sea. Economically producible hydrocarbons have been proven in the Realgrunnen and Kobbe formations. Production strategy consists of periferic water injection for pressure maintenance and gas injection in the gas cap for disposal purpose.

The development plan includes the distillation of intermediate components from the separated gas phase. This can not be easily modelled within a black-oil reservoir simulator, because the process efficiency depends on gas volumes and gas molar composition that change along with the depletion of the reservoir. A possible solution is to build a reservoir-process model to provide corrected production profiles, and the efficiency of the solution relies on accurate and robust method to delump the black-oil streams.

We modified a well-known delumping method to account for Goliat peculiarity. Detailed fluid composition is calculated at each well completion. Phase molar flow is characterized interpolating the composition measured in differential liberation test. Since the gas is expected to be partially produced from the gas cap, the original method has been modified to distinguish between dissolved and dry gas composition, following the latter in the simulation as a tracer carried by the gas phase.

The application of this delumping algorithm offers several advantages. First, this method is cost-effective because it can be implemented efficiently by post-processing black-oil well streams, avoiding a much more time-consuming compositional simulation. Secondly, it increases the accuracy of forecast profiles since it takes into account the variation of the produced fluid composition with time. Finally, it provides sale-gas composition forecast according to the surface process facilities.
Design, Execution, and Results of the Longest Multizone Cased-Hole Gravel-Pack Completion in Malaysia
Authors: Saebi Shahryar , Tyutikov Sergey , Machado Angel , Curteis Charles , Rivero Maria Elba , Khaled Mohd Zaidan , Habib Mohamed Said
Published: July 2010

This paper reviews the sand control practices used in an offshore Malaysia field, including execution of the longest single-trip multizone cased-hole gravel pack in Malaysia, the challenges faced, and the lessons learned.

PETRONAS is currently developing an offshore field in Malaysia with wells designed to obtain medium-to-high production rates and be completed as gas-lifted dual-string producers. The lower sandface completion design was to gravel pack the lower and middle zones on a single run and selectively produce through the long string. The upper zone was then to be gravel packed and produce through the short string. Because of the long perforated intervals and exceptionally long distance between the producing zones, as well as different pressure profiles of the layers, shunt tube technique was identified as being the best practical method to overcome the operational challenges. The target reservoir is a laminated and multilayer sandstone formation. The lower and middle zones were gravel packed simultaneously with gross-producing intervals to 950 ft (the shaly section between the zones up to 600 ft). The upper zone was gravel packed separately with a gross perforated interval length to 775 ft. Due to the different pressures in the multiple zones, loss and crossflow control was a design requirement.

The project imposed a number of challenges, including gravel packing extremely long intervals while aiming to achieve suitable perforation packing efficiency in unconsolidated and soft sandstone formations and also providing the possibility of selective production during the life of the wells. The proposed solution to overcome these concerns consisted of combining shunt tube technique with a three-way sub-concentric completion system.

Five wells using this design have successfully been completed in this project with sand-free production rates exceeding expectations.

The proposed solutions and the lessons learned in this project could change the sandface completion practices for multizone and long intervals in the offshore Malaysia fields. The techniques used in this project resulted in considerable rig-time savings, lower skin, and better productivity through improved perforation packing efficiency compare to the conventional methods.
Downhole Scale Control on Heidrun Field Using Scale Inhibitor Impregnated Gravel
Authors: Selle Olav Martin , Haavind Frode , Haukland Marit H. , Moen Arild , Hals Carl F. , Øien Kåre , Strachan Catherine , Clark Graham
Published: July 2010

Scale inhibitor impregnated gravel (SIIG) is a new technology for combined sand and scale control that features porous ceramic proppant particles that are impregnated with scale inhibitor chemistry. The particles have been designed to be suitable for gravel pack pumping operations and can be pumped as 100% scale inhibitor impregnated particles or mixed with conventional gravel. The scale inhibitor impregnation technology has been optimised to provide a steady, controlled release of scale inhibitor chemical on contact with produced water. The technology provides for the first time in the oil industry a method of placing large quantities of solid state scale inhibitor in gravel packs. In typical gravel packed deepwater completions, particularly, sub-sea wells, the technology offers considerable cost benefits for scale control when compared to scale inhibitor squeeze treatments and negates the need for pre-emptive squeeze treatments in anticipation of seawater breakthrough.

After qualification of the product through a comprehensive laboratory development programme a field trial has been performed on a Heidrun well. The well was a sidetrack from the mother well, and it was chosen for the field trial as the initial water breakthrough was predicted to contain around 20% sea water. The field trial demonstrated that placement of the scale inhibitor impregnated particles could be successfully performed. However, the loss of scale inhibitor to the gravel pack fluid was higher than anticipated since it took three weeks between gravel packing and startup of the well. Despite the high intial loss of scale inhibitor to the gravel pack fluid the release of inhibitor during production was as planned. Unfortunately it did not protect the well from scaling since the mixing of sea water and formation water probably took place in the near well area behind the gravel pack.

This paper will provide a detailed description of the laboratory development of SIIG technology and, in addition, will also present details of the first gravel pack deployment of this technology for combined sand/scale control in a Heidrun well.
Phase Behavior of Steam with Solvent Coinjection under Steam Assisted Gravity Drainage (SAGD) Process
Authors: Li Weiqiang , Mamora Daulat D.
Published: July 2010

A detailed investigation of the phase behavior inside the steam chamber is important to understand the drainage mechanism of solvent co-injection under steam assisted gravity drainage (SAGD) process. A 2D simulation study based on typical Athabasca reservoir properties with hexane (C6) as the coinjection solvent shows that a successful solvent co-injection design can take both advantages of solvent and steam.

Due to differences in the boiling points of solvent and steam, the phase behavior inside the steam chamber is not uniform and is not the same for different production stages. The gas solvent, liquid solvent, and water accumulated along the oil-steam interface work together to affect the oil viscosity in a complex relationship. Based on results of this study, we suggest some directions of future research to improve solvent coinjection performance.
Pseudo-Steady State Productivity Equations for a Multiple-Wells System in a Sector Fault Reservoir
Authors: Lu Jing , Ghedan Shawkat
Published: July 2010

Wells producing from their own individual drainage area is only true for reservoirs at their early development. However, in matured oil reservoirs it would be acceptable to imagine several wells producing from the same drainage domain. Each well, then, will have an effect on the pressure of other wells. The flowing bottomhole pressure of a well producing at a constant rate is a function of its own production as well as the production from surrounding wells. Currently, in the oil industry, productivity equations for single wells are erroneously used, as they do not consider the interference effects on flow rates of different wells in the same drainage domain.

This paper presents a pseudo-steady state productivity equation for a multiple-wells system in a homogeneous, anisotropic sector fault reservoir with impermeable boundaries. Assume sector angle Φ is equal to π/n, n is an integer bigger than 1, take fully penetrating vertical wells as uniform line sinks, and use symmetry principle, a simple, reasonably accurate productivity equation for a multiple-wells system is obtained by solving a square matrix of dimension 2nm, where m is the number of wells. The proposed equation relates the production rate vector to the pressure drawdown vector, is applicable to a multiple-wells system arbitrarily located in a closed sector fault reservoir. Convenient algorithms to calculate shape factors for sector fault reservoirs, equilateral triangle reservoirs and isosceles right triangular reservoirs are provided. The value of the shape factor from the proposed equation is very close to its corresponding value published in the literature.

The benefit of the analytical model can be emphasized when the reservoir data deviate from their idealistic representation. It is concluded that, the proposed equations provide a fast analytical tool to evaluate the performance of a multiple-wells system in a closed sector fault reservoir.
Study on Development Mechanism of Commingling Production in Low-permeability Gas Reservoirs
Authors: Guo Ping , Wang Juan , Liu Qi-guo , Zhang Mao-lin
Published: July 2010

Low-permeability, low-production, low-abundance are the major features of the low-permeable gas reservoir. Commingling production has been widely used as an important method to improve the producing ability of gas reservoirs, however, the dynamic analysis and technical countermeasures for the multi-commingled wells are still not enough.

Started from the multi-commingled filtration theory model, the pressure characteristics and the contribution rate of production of each layer, which are under the different multi-commingled well conditions such as reservoir properties differences, interlayer pressure difference and different damage degree, are studied in this paper. The results show that the contribution rate is fixed on formation coefficient before the pressure wave reaches the boundary; and after that, it is fixed on the storage ratio, it could be fixed on the formation coefficient, storage ratio and kickoff pressure gradient when considering the kickoff pressure gradient. Although there are significant differences in permeability between layers, the well test pressure curves have little difference.

Taking the Da-niudi gas field for example, the single layer production rate, recovery and total recovery are studied by numerical simulation at different permeability ratio in multi-commingled well. The results show that the different permeability ratio contrast (<10) models can all be commingled. The total recovery of different models has little difference, when the formation pressure declines to the abandonment pressure. However, the smaller the permeability contrast is, the longer the stable production period of the well is, and the less the interlayer recovery difference is; on the contrary, the shorter the stable production period is, and the larger the interlayer recovery difference is.

All the reservoirs in the multi-commingled well had better to be put into operation at one time. In this way not only the operation to succeed the late fill-holes can be saved, but also overall commingled layer recovery could increase.
Reservoir Architecture Characterization: EOS-Based Downhole Fluid Analysis, Openhole Logs and Pressures Integration
Authors: Xian Cheng Gang , Zuo Julian Y. , Haddad Sammy , Berrim Ahmed
Published: July 2010

Reservoir hydrocarbon fluids complicated properties and phase behavior with associated physics often reflect the complexities of reservoir architecture. Hence, it is of great importance to determine fluid heterogeneities at the early exploration and appraisal stage. Conventionally, however, gathering information on fluid heterogeneities and phase behaviors is a challenging process that requires numerous fluid samples and associated laboratory analysis. Although pressure gradients are often used to evaluate in-situ fluid densities, contacts, or connectivity, this method may be misleading as fluid compositional changes and compartmentalization give distortions to the pressure gradient fitting. Nowadays, Downhole Fluid Analysis (DFA) measurements are being effectively used to reveal fluid heterogeneities by providing various reservoir fluid properties in real-time. In order to allow an objective assessment of reservoir architecture, it is needed to incorporate a rigorous mathematical approach in respect of all data available.

This work demonstrates with field data an effective and reliable methodology for evaluating fluid variations with depth through an equation-of-state (EOS) approach by interpreting DFA measurements integrated with other conventional data. Using an established method, the topmost DFA data in a column was delumped and characterized, and then an EOS model is established for the reservoir fluids. The EOS parameters can be tuned to match DFA measurements at different depths. The tuned EOS is applied to predict compositional and property gradients with depth. If the difference between the predictions and DFA data is significant, then potential vertical discontinuity between the top pay zone and current depth must be investigated. Case studies are presented to illustrate how this methodology is applied. This work demonstrates that the EOS based methodology of integrating DFA data with other openhole logs provides a powerful tool of characterizing reservoir architecture, which is invaluable for optimal reservoir management and development.
Comparisons of Various Algorithms for Gas-lift Optimization in a Coupled Surface Network and Reservoir Simulation
Authors: Samier Pierre
Published: July 2010

Gas lift is used for gas-liquid two phase producers to boost the production. Increasing gas liquid ratio GLR reduces the average fluid mixture density in the well connections and therefore reduces the hydrostatic pressure drop and hence reducing the bottomhole pressure resulting in a higher production rate or a longer individual well production period. This technique is also used for deep offshore fields injecting the gas at the toe of the FPSO risers located at the seafloor.

But as the lift gas supply is increased further, friction pressure losses in the tubing or the riser become more important and the production rate peaks then starts to decrease. Also high gas flowrates may induce corrosion problems, and the total amount of available gas-lift is limited. Therefore an optimal gas-lift rate exists for a maximum production rate or more generally a maximum production profit.

Various gas lift optimization algorithms have been proposed in literature for optimizing gas-lift to individual wells or within a group of wells, very few are suitable for long-term reservoir development studies with gas-lift injection within a network (FPSO riser toe for example).

Commercial simulators such as Eclipse, VIP, Nexus, … provide internal optimization tool which are convenient for gas-lift at wells connections. Optimizing gas-lift within a network with additional gas rate inside flowlines or risers becomes much more complicated since the THP limits of all the other wells in the network are affected. Each time a lift gas increment is added or substracted, the whole network must be rebalanced with the appropriate lift gas rate in order to recomputed the change in the field oil production rate. The paper reviews some of the optimization methods available in commercial coupled surface network and reservoir simulators such as Resolve -Gap-Eclipse, Nexus, Avocet, …

Several optimization algorithms linked to a surface facility model coupled to an open reservoir simulator prototype have been also applied (Ensemble based method, Steepest-Descent, Gauss-Newton, BFGS,..) and compared to previous commercial software solutions.

Results of the comparisons are presented on a surface network model coupled to a reservoir simulator where the objective is to optimize the gas-lift allocations at riser toes.

One of the test cases based on a modified SPE 9 comparative test is fully documented and allows the readers to compare results with their own optimization algorithm.