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Abstract Stringent environmental regulations and higher costs of effluent treatments in oil and gas process industries have necessitated research into ways to improve the operating procedures in effluent treatment plant. In Gas-to-liquid (GTL) plant, a significant quantity of reaction water is produced and various chemicals are used as intermediate treatment chemicals. The reaction water is contaminated by these chemicals which impair the pH and the related properties of the water. The pH has to be controlled before the water is re-used or released to the environment. A laboratory-scale effluent neutralization unit for pH control was designed and built to demonstrate the feasibility of utilising produced carbon dioxide (CO2) from reforming reactions in both the synthesis and hydrogen production units in GTL plant for insitu effluent treatment. At the end of the reaction, the total volume of carbon dioxide used was recorded. This paper presents experimental neutralisation characteristics for different operating conditions. The prime advantage of this process can be thought to be less expensive than other published carbon capture and storage (CCS) processes. Moreover the carbon dioxide does not require further compression, dehydration and storage facilities before usage. Pipeline transportation is also drastically reduced since the captured carbon dioxide is utilised within the plant. This study demonstrated that, the neutralisation time increased by 3.15 minutes with increase in effluent volume from 40 to 60 litres and by 10.4 minutes as the temperature increased from 20oC to 50oC. The increase in the flow rate of carbon dioxide from 15 litres/min to 35 litres/min decreased the neutralization time from 19.15 minutes to 13.32 minutes. Finally it was estimated that about 64% of the daily carbon dioxide production which would have otherwise been emitted to the atmosphere was used in the treatment process. Introduction The fact that the concentrations of carbon dioxide in the atmosphere are increasing is known to environmentalists, researchers and government agencies. The causes of global change lie in the industrial activities of human society and ultimately in the population growth and increase in resource use by man. Human activities have increased carbon dioxide concentrations from approximately 280 to 355ppm since 1800 (Vitousek, 1994). This increase is likely to have climatic consequences on biota in all earth's terrestrial ecosystems. The need to reduce global climate change due to emission of carbon dioxide (CO2) and other greenhouse gases has led to research in carbon capture and sequestration (CCS). Several relatively small-scale carbon capture and sequestration approaches are currently in development and demonstration stages as highlighted by Hoekman, 2010. Direct injection into the oceans has also been suggested but there are a number of uncertainties over the ecological impact and equilibrium of the gas with the atmosphere. In the medium term, depleted oil and gas reserves, unmineable coal seams, and deep saline formations are the best options for carbon dioxide storage. Deep saline formations appear to offer the potential to store several hundreds of years' worth of carbon dioxide emissions. This must be validated, and site selection criteria must be developed and shared internationally to identify the most appropriate storage sites. Wider international collaboration and consensus are critically needed to ensure the viability, availability and permanence of carbon dioxide storage. However carbon capture and sequestration faces both technical and economic challenges. Therefore, there is the need to explore other methods to deal with carbon dioxide emissions. Transformation to chemical feedstock like methanol is a commercially proven technology, however carbon dioxide captured from flue gas from furnaces will not be economical for this purpose because of its low pressure. Recompression is required before the carbon dioxide could be processed to methanol (Ritter et al, 2007). Another well-known process - the Sabatier reaction, converts carbon dioxide to methane as shown in Eq. (1).

Abstract This paper presents the results of laboratory treatment works on upgrading the bentonite from two areas of Sabah, Malaysia, namely Andrassy and Mansuli for the uses in petroleum industry. Bentonite, as a common material used in water based drilling mud is the sodium bentonite. Since the Malaysian bentonite is proved to be calcium based, certain treatment is needed to convert this bentonite to sodium variety. The successfully treated bentonite will be used as a material in drilling mud, which is cheaper as compared to the Wyoming and standard bentonite. This study included two treatment processes; wet treatment and electrolysis. Several sodium sources have been studied but only the sodium carbonate can successfully be used to upgrade the bentonite. The results obtained after these two treatment processes showed improvement in cation exchange capacity (CEC), which is about 27% increment for electrolysis treatment and 22% to 29% for wet treatment, respectively. However, the treated bentonite failed to meet the API 13A Specification (American Petroleum Institute) requirements for rheological properties when used as a material in drilling mud. Thereafter, certain polymer extender had been added to improve rheological of the upgraded bentonite slurry so that it can be used as a drilling mud material. In general the treated bentonite from Malaysia can be used as a replacement for the more expensive imported bentonite especially for local petroleum industry. In addition, the methods developed can also be used to convert the similar type of bentonite from other locations, since the large deposits of calcium based bentonite can be found in Malaysia. Introduction In order to reduce the overall cost of bentonite used in local oil and gas industry, the feasibility study of Mansuli and Andrassy bentonite application had been initiated. Before these bentonite can be used, their physical and chemical properties and their performance as compared with the standard bentonite must be determined. If their performances are not as good of standard bentonite, treatment ought to be applied to convert the counter ion that placed between the unit clay surfaces. The type of counter ions has a great effect on the swelling capacity of the montmorillonite mineral and by far the best performance is obtained with sodium-based montmorillonite mineral, which has sodium as counter ions. If the montmorillonite mineral in bentonite contains counter ions other than sodium, the swelling properties, viscosity build-up and filter cake permeability will be adversely affected. Three sources of samples that were used in this study, two sources namely SA5–1 and SA5–4 from Andrassy of Tawau area and the other namely M4 from Mansuli of Lahad Datu in Sabah. These bentonite are proved to be non-sodium based, which are different from the commercial sodium based bentonite according to chemical composition, chemical and physical properties such as Atterberg limits, moisture content, moisture adsorption, ignition loss, specific surface and cation exchange capacity. Experimental Works Bentonite Sample Preparation Bentonite samples from the field will be dried in the oven at 55 °C for four hours until moisture content become less than 10%. Then the sample will be crushed using grinding machine till it become powder. Selection of bentonite grain size is very important to obtain optimum cation exchange. API Specification 13A showed that the needed particles size to be used should less than 74 (m, which can be achieved by using wire cloth sieve. Mineral Composition X-Ray Diffraction (XRD) analysis had been used for mineralogy determination and the test was done by using Siemens D-5000 fully automatic diffractometer. The mineralogical constituents within the bentonite sample can be directly characterized giving critical information as to the geological evolution of rock samples.

Predicting the effects of the fracture penetration ratio and fracture conductivity in hydraulically- fractured vertical wells in dry-gas and wet-gas reservoirs is important in determining the well performance in a given formation. A fracture length and conductivity which provide the highest ultimate gas recovery factor at the earliest time to reach abandonment conditions is the proper fracture type which has to be selected for developing the reservoir. A three dimensional reservoir simulation model is used to evaluate the performance of hydraulic fractured vertical wells as a function of fracture penetration ratio and fracture conductivity. Accurate determination of initial gas reserves, average reservoir pressure at abandonment time, and the time to reach abandonment conditions is very important to the petroleum industry. Material balance technique and volumetric method, currently used in the petroleum industry to determine the reserves, which do not consider well performance and, as a result, predict a very high recovery factor at abandonment pressure for hydraulic fractured vertical wells in volumetric dry-gas and wet-gas reservoirs. Well performance in hydraulic fractured vertical wells depends on fracture penetration ratio and fracture conductivity. A comparison with horizontal wells of same penetration ratio is also provided in this paper as an alternative to hydraulic fracturing. A number of simulation runs were performed on a square shape reservoir of horizontal permeability 0.01 md, 0.1 md and 1 md with a penetration ratio of 0.2, 0.4 and 0.8. Our results quantify and show that the ultimate recovery factor and abandonment time are function of fracture penetration ratio regardless of fracture conductivity. In addition, our results shows that in low permeability reservoirs a hydraulic fractured vertical well of similar penetration ratio to a horizontal well perform twice in terms of recovery factor and abandonment time. The effects of formation thickness, well parameters and reservoir rock properties on the average reservoir pressure at abandonment time and on the time to reach the economic limit are also presented in this paper. Based on the results of fracture penetration ratio and fracture conductivity in volumetric dry-gas and wet-gas reservoirs, this paper presents recommendations regarding the proper well type with which the reservoir should be developed.

Capillary pressure relationships (drainage) involve key SCA parameters measured in the laboratory. Reservoir engineers use capillary pressure relationships in reservoir engineering calculations and dynamic reservoir simulation and petrophysicists use such relationships in saturation-height modelling. The objective of this paper is to describe a novel technique to identify pore throat or grain size distributions from capillary pressure profiles. Capillary pressure, laboratory data are traditionally obtained from three different types of experiments: centrifuge, porous plate and mercury injection. The modified Carman-Kozeny Purcell (MCKP) model may be used in matching various laboratory results. Initial application of the MCKP model involved a standard matching procedure without differentiating according to the type of pore throat or grain size distribution. In this paper a refined, more powerful analysis technique is described in detail where matching of any laboratory data with the MCKP model is obtained in model space, showing various characteristics. Characteristic profiles observed in model space can be directly attributed to the type of pore throat or grain size distribution: homogeneous (narrow), broad (poorer sorting) and bimodal (two distinct distributions), or a mixture of distribution types. Comparison of model generated profiles with laboratory curves indicate a high degree of congruence, typically R2 > 0.99, consistently better than any other capillary pressure formulation. The technique is also able to pick up artefacts, such as a sample fracture or laboratory procedural issues. It is shown how the MCKP model may be used in predicting capillary pressure relationships from basic parameters by building a framework based on end-point correlations derived from available laboratory data. The paper presents various examples and a detailed case history for the Bayu-Undan gas field, covering various pore structure and diagenetic characteristics.

The low permeability reservoir development effects can be effectively improved with the use of advanced water injection technology, which means the water is injected several months before the oil production. Advanced water injection can improve the formation pressure in advance, and establish an effective displacement system. However, with the increase of reservoir permeability, the increasing value of recovery tends to decline in advanced water injection. Therefore, it is necessary to study the permeability limits of advanced water injection. In this paper, the laboratory experiments of the low permeability natural core from A oilfield were carried out, and the changes of core permeability, pore structure and oil displacement efficiency in advanced water injection were analyzed. Meanwhile, the changes of sweep efficiency and recovery in advanced water injection were figured out with numerical simulation method, and the effect of advanced water injection tested in A oilfield was analyzed. The results of the laboratory experiments showed that, for the cores of permeability less than 10.0 mD, as the core pressure drops from 19.0 MPa to 17.0 MPa, the permeability declines by 15.0 percentage points. When the pressure is restored, the degree of permeability recovery is 2.0 percentage points. Also, with the pressure increase, the oil displacement efficiency of the core permeability less than 10.0 mD increase 1.2 percentage points, while the oil displacement efficiency of the core permeability above 10.0 mD increase only 0.3 percentage points. The results of numerical simulation showed that, with the use of advanced water injection in the formation of permeability less than 10.0 mD, the sweep efficiency increases by more than 5.0 percentage points and the ultimate recovery increases by more than 0.4 percentage points. In addition, the effect of advanced water injection tested in A oilfield was much better than that of the conventional water injection oilfield. The daily single well oil production was 1.6 multiple higher than that of the conventional water injection oilfield, and the annual decline rate was 13.0 percentage points lower than that of the conventional water injection oilfield. Taken together, the permeability limits of advanced water injection is 10.0 mD, and better development effect and higher recovery can be obtained with advanced water injection technology for reservoirs of permeability less than this value. This paper can provide a reservoir screening criteria for the advanced water injection technology and can guide the further application of this technology in low permeability reservoirs.

In this paper, the multi-stage preconditioners are modified and applied to dual-porosity/permeability (DPDK) model problems. Employed as the first step of the multi-stage preconditioning processes, two modified decoupling processes for DPDK problems are developed. In a DPDK model, mass transfer both between fractures and between matrices is allowed, which means that the pressure both in fractures and matrix behaves as an elliptic property, so it is natural to employ two preconditioning stages solving the fracture pressure system and the matrix pressure, respectively, which draws the first type of a multi-stage preconditioner in this paper. Since the transmisibility between fracture blocks is much higher than that between matrices, the elliptic property of the fracture pressure is much stronger. Hence, we remove the stage of solving the matrix pressure system in the second type of a multi-stage preconditioner. Moreover, an extra stage of the ILU preconditioning process is added to the above multi-stage preconditioners in order to improve their efficiency, which results in another two multi-stage preconditioners. Combination of the modified decoupling processes and four new multi-stage preconditioners are studied and compared by large-scale reservoir simulation problems. Based on these numerical experiments, the optimal method to solve the DPDK model problems is concluded.

In this paper, we describe the use of an innovative approach in the preparation process of the input log data for predrill geomechanical modeling, as well as real-time wellbore stability model update during drilling. The paper presents the methodology and justification of the solutions found to restore the missing data in "slow" formations with low values of the speed of passage of acoustic waves at shallow depths for geomechanical modeling, detection and prevention of risks during well construction. In the context of the "slow" formations at shallow depths (up to 1200-1400m TVDSS in the Yamal region), as well as logging tools restrictions, it is often impossible to detect shear acoustic waves, which, along with the compressional acoustic wave and other log data is also necessary for geomechanical modeling. Given these circumstances, and due to the inability of recording full-wave wireline acoustic logging conducting geomechanical modeling for the upper sections of the well is very difficult. Based on the analysis of acoustic logging data in the Yamal region, we have managed to build a regional dependence of compressional and shear acoustic waves and generate synthetic recovery of the shear wave velocities in the zones of missing data, which has been confirmed by the actual loging while drilling data. The result of the discovered regional dependence of compressional and shear acoustic waves was the restoration of the missing portion of the upper interval logging that has allowed to carry out predrill geomechanical wellbore stability calculations in the absence of the necessary log data. Because of predrill geomechanical modeling during project preparation for the construction of the well it became possible to substantiate the need for adjustments in the project documentation regarding the use of project specific mud weights. According to this model, significant collapse of the borehole wall was possible in the case of expected design specific mud weights. Thus, the specific mud weight have been significantly adjusted for each section. The resulting dependence has also been used during the drilling process, in the cases when it was not possible to obtain correct shear wave velocity logging data due to external factors. These adjustments to the drilling program on the stage of well design, combined with the early identification and prevention of drilling risks based on constantly updated geomechanical model played a key role in the accident-free drilling of the first directional well with inclination angle of more than 70 degrees in the field. The experience and achievements have also been used in a number of similar projects in the Yamal region, where it was possible to get a satisfactory convergence of the reconstructed and actual data, which enables the use of findings on the other projects of Yamal region.

A 3D geomechanical model was constructed to estimate the influence of the initially placed propped fractures and the pressure variation with time in active field development on the stress-state redistribution. The main task of paper was to research the different parameters influence on stress state condition and especially on possibility of stress reorientation due to field development. In addition, the main purpose of the paper is to fiend impact of acting processes on hydraulic fracturing propagation. A finite element method was applied to calculate the stress state in a target sector of the oil field. All available seismic data and pertinent well logging data were used to update the geological and hydrodynamic models, and data from hydraulic fracturing, 1D geomechanical modeling, and drilling history were used for verification of the modeling results. In the following paper the reservoir parameters which can be useful for other fields of West Siberia were used. The 3D geomechanical model was created and used for the stress-state redistribution forecast, taking into account the field development history. The model was built by coupling the geomechanical finite element and compositional numerical reservoir simulator result at two time steps –the initial, virgin state and the current state of the field development. It has been shown that the change in reservoir pressure has a significant influence on the value of the horizontal stress in the area of interest, whereas the change in stress orientation depends on the reservoir height, layout of wells, field development stage, and mechanical properties of the rock. Near the initial fractures, the fractures themselves have a strong influence on the magnitude and orientation of the horizontal stress.

ERD drilling is associated with both technical and technological issues that need to be considered from the first planning stage which directly affects the job successful execution. The Paper summarizes the best practices and solutions related to casing running and cementing in ERD wells, describes the importance of geomechanics modeling, special features of casing running and cementing in ERD wells. The purpose of this Paper is to develop an understanding of recent solutions and best practices related to ERD wells construction from the very beginning.

Naturally fractured reservoirs present a production paradox. It is not an exaggeration to say that the big part of the world oil and gas reserves are concentrated in naturally fractured reservoirs (NFR). Naturally fractured formations may have different genesis. Igneous, metamorphic and sedimentary rocks undergo of fracturing and faulting as well while forming extensive and narrow system of highly conductive zones. In this paper, we investigate and analyze core study results, interference test results conducted in naturally fractured formation on gas field, draw conclusions about the conducted test and analyze interpretation results. At the end of this paper, we give recommendations for using the test for determinations of high permeable zone in naturally fractured reservoir.

Dielectric logging is used in oil and gas exploration for estimating the hydrocarbon content of the reservoir and rock texture. This information is essential for making decisions on development and production of reservoirs. This paper looks at using dielectric dispersive behavior of formation and how it can be related to widely used parameters of Archie's law in petro-physics. In dielectric logging, the electromagnetic properties, permittivity and conductivity of the formation are obtained over a frequency range. These properties exhibit a variation with respect to frequency, which is called dispersion. The dispersive behavior of formation as a whole is different from that of its constituents; water, oil and dry rock. This dispersive data can be used to obtain various petrophysical properties like water saturation, water resistivity and rock texture. Alternatively, Archie's law is widely used to relate the resistivity of formation to the resistivity of water, porosity and water saturation. The so-called Archie parameters, cementation and saturation constants, are widely used in petrophysics. This paper discusses a novel approach that uses the dielectric dispersive behavior of a formation to provide a link to parameters of Archie's law. There exist many mixing laws that predict the dielectric dispersive behavior of a rock as a mixture of water, oil and dry rock. The proposed approach can be applied to any mixing law to provide parameters of Archie's law. Detailed derivation of the Archie's parameters from known dispersive laws is provided through examples. The method is applied to published data on dispersive behavior of sample rocks and its prediction of Archie's parameters is compared with the values obtained from experiment. The proposed method is capable of relating textural parameters of rock used in mixing laws to Archie's parameters.

Teak, Samaan and Poui (TSP) is a mature field off the South-East coast of Trinidad, which currently produces near to 14,000 bopd with an average Water Cut of 85%. In production since 1972, it peaked at 143,300 bopd in 1978. Repsol E&P T&T has been looking to increase oil recovery by unlocking the remaninig potencial of their reservoirs in Sands 01, 02, 1/2 and 2. An interdisciplinary and detailed study was generated between several disciplines, including geology, petrophysics and reservoir engineering, to re-evaluate these sands, where a waterflooding project had been implemented between the 70's and 90's with seemingly good results. A Static Model was generated starting from a detailed well by well analysis (well logs and core information, seismic, production and pressure data, etc…), where some problems, related to uncertantly in the Structural Model and to the interpretation of the input data had to be overcome. This paper explains the workflow that was used to create this static model. First, the originally suspected several Oil Water Contacts (OWCs) had to be analyzed. The area is affected by several fault blocks with varying juxtaposition of the geological layers, which lead to the interpretation, in previous studies, of several contacts. A solution to this and to the effect that this juxtaposition has in the flow within the reservoir and in the pressure distribution is analyzed in this paper. The next step was to reach to a rock type definition based on k/phi relations and a J Function (J(Sw)), with the challenge of having insufficient Core Data and Pc curves. An additional challenge faced was the questionable resistivity logs, which are suspected to have been affected by drilling mud throughout the successive drilling campaigns. Then, in order to define permeability and water saturation models, an alternative workflow was tested and implemented. This method includes conventional rock typing analysis (Pc derived J(Sw)) and extrapolation of these results to the wells. This, together with the resistivity logs (Sw), has been used to compute permeability above the OWC. Threrefore, this allows us to calculate permeability first, and then use it in the J function to calculate the water saturation that will be input into the model. Finally, a Lorenz plot was built to define flow units and identify the possible water injection paths.

This paper describes a laboratory and modelling study into halite (sodium chloride, rock salt) deposition in mature gas production wells. Halite deposition can result in significant production and integrity issues, and mitigation measures are primarily based upon injection of low-salinity wash water, often coupled with careful control of production parameters (such as well drawdown), for which scale-prediction models are used. Laboratory investigation of halite scaling and performance of halite inhibitors typically uses the mixing of incompatible brines or cooling a saturated solution, either in bottle tests or using a dynamic scale rig. While these methods allow precipitation kinetics and inhibitor performance to be examined, they are far from ideal as they require significant modification of the brine chemistry and deposition conditions. In this paper, we describe a novel approach to laboratory investigation of halite deposition that much more closely mimics the evaporative scaling mechanism mostly widely experienced in the field, and can be performed using produced-water compositions and conditions that are much more representative of the field. It is based upon a dynamic, flowing system where field-representative formation water is co-injected with gas at an appropriate level of under-saturation in water content to that expected under production conditions. Electrolyte prediction software was used to model the halite scaling tendency in the experiments, and very good correlation was found between the prediction of supersaturation and the onset of precipitation and deposition. This agreement implies that the scale-prediction model is accurate for halite scaling via this mechanism, and adds much confidence to the use of this tool for optimizing production parameters to minimize the effects of halite scaling in the field. The work also confirms earlier reports that the critical scaling tendency for halite – the value at which significant precipitation and deposition occurs in the field – is very close to unity for the conditions tested in this work. The new laboratory method was also used to generate calcium carbonate scaling by the mechanism – primarily transfer of CO2 to the gas phase – that is by far the predominant one found in the field; this led to observation of a mixed halite/calcium carbonate deposit.

Scale inhibitor squeeze treatments in high-permeability sandstone reservoirs can be readily simulated using matrix flow models. However, designing such treatments for application in fractured shale reservoirs is less developed, partly because the mechanisms for fluid flow are less well understood and partly because the manner by which the inhibitors are transported and retained in fractured shale formations differ considerably from the simple matrix flow encountered in sandstone reservoirs. Accurate prediction of squeeze treatment lifetimes is important for scale management both economically, to ensure optimum productivity at lowest cost of operation, and practically, to schedule treatments appropriately. Until recently this has not been achievable for fractured shale formations without the use of full-field simulators. This paper demonstrates that even a near-wellbore model, if appropriately modified, can achieve good agreement with inhibitor-returns field data from bullheaded squeeze treatments in 7 different multiply fractured wells in 2 different Unconventional shale formations. Field data were compared with simulations using a model that couples inhibitor diffusion into and out of the rock matrix with adsorption either onto the rock matrix or the fracture proppant or both; it was found that in some field cases there is negligible difference between inclusion or exclusion of proppant adsorption, whereas in others much better simulation of inhibitor returns is observed if proppant adsorption is included. Other aspects have been included in the model, such as the influence of proppant embedment (changing the porosity of the fracture void) and treatment of only a fraction of the multiple fractures present in a well. Interestingly, inhibitor returns in the 3 wells in one field correlated best with simulations assuming only a low fraction (up to 30%) of fractures were treated by the squeeze, whereas simulations from 4 wells in another field correlated better with a much higher fraction of fractures (60 – 90%) being treated. This paper illustrates that an appropriate near-wellbore model can give good agreement with field data provided plausible physical phenomena are included, and that such a model can be used to design better squeeze treatments in Unconventional fractured-shale reservoirs without the need for complex full-field simulators.

Production data analysis of neighboring wells in Williams County, ND shows some 100% ceramic proppant completions do not show adequate production improvement needed to justify the additional cost of ceramic proppant. These results are contradictory to laboratory API proppant pack conductivity (API RP 19-D) or proppant pack mechanical strength (API RP 19-C) measurements which predict superior performance of all types of ceramics compared to sand. This study evaluates the ability of current API procedures to predict proppant behavior in horizontal wells and suggests a modified API testing procedure which considers the performance of thin layer/monolayer proppant packs improving the correlation between the laboratory and well production data. The study also compares the mechanical strength of 20/40 and 30/50 white sand, clay based economy lightweight ceramics and bauxite based intermediate strength ceramics using standard and modified API RP 19-C crush resistance tests. During testing, load cell volumes range from the standardized 4lb/ft2 to the modified 0.5 and 0.25lb/ft2. 0.5 and 0.25lb/ft2 volumes simulate proppant behavior in hydraulic fractures with frac widths approaching 0.12″ and 0.07″, respectively. Mechanical failure of proppants is quantified by comparing proppant size distribution pre- and post-stress application using a Horiba CAMSIZER. Failure of proppants is also measured using in-situ high pressure CT scanning protocol that enables visualization of the proppant failure as a function of applied load, proppant type and proppant pack thickness. The study establishes large differences in mechanical performance of tested materials under thick (4lb/ft2) and thin (0.5 and 0.25 lb/ft2) proppant bed height conditions. In the case of white sand, even at pressures as low as 4,000psi, the amount of material failure is 3 times higher at 0.5lb/ft2 and 5 times higher at 0.25lb/ft2 compared to the API standard (4lb/ft2). Both types of tested ceramic proppants also show a higher % of mechanical failure in lower bed height conditions. While the mechanical performance of the tested ceramic proppants is better than that of sand, the performance of clay based economy lightweight ceramics at 8,000psi is drastically reduced and begins to approach that of sand. This is most prominent for 30/50 mesh distribution samples. In situ high-pressure CT scanning identifies two different failure mechanisms in the tested proppants.The study then compares laboratory data to publicly available well production data in Williams County, ND. Production increases seen in 100% ceramic completions shows a strong correlation to laboratory measured performance of proppant at 0.5 and 0.25lb/ft2. This paper quantifies the effect of reduced fracture thickness to the performance of different proppant types. In addition, this paper introduces a novel in-situ high pressure CT scanning protocol and provides unique insight into proppant failure mechanisms found in thin, unconventional fractures.

This paper describes the analysis and positive results of injecting water, from constant to discontinuous rates in a reservoir under a high water cut stage. By following and improving waterflooding surveillance applications it was possible not only to describe the kind of reservoir, but also to keep the water cut up for a longer time. The goal of this study is to demonstrate the powerful benefits of applying and improving the surveillance plots that are available in the existing literature. The pore volumes injected plot, which was enhanced in this study by adding the injection rates per well in a secondary Y axis, was a powerful tool to identify the water cut behavior. One of the two injector wells of the field was shut in for about 5 months and returned to its water injection conditions for 7 months. These events are presented in three phases. The first is related to the reservoir characterization achieved before the injector shut in. The second includes the well responses observed and monitored during the injector shut in. And, the third illustrates the promising reservoir results after the injector shut in. As well, an economic model is also developed. As a result of the field events, analysis, and results described in this paper, the reservoir water cut was stable for a longer time in comparison with the whole life of the IOR project. In addition the increase Estimate Ultimate Recovery was 304,968 bbl for 8 years, the net present value of the field increased to 24%, and the average operating cost was reduced to 2.49 USD/bbl from 2015 to 2022. The cyclic waterflooding existing literature supports reservoir characterization, analysis and results achieved in Tiguino Field. The initial application monitored in Ecuador will be helpful to be considered as a first approach for starting an IOR optimization in similar stratified reservoirs. The results obtained in Tiguino field are helpful not only as a real example but also as a statistical support for cyclic waterflooding. The Tiguino case experience would be extrapolated to other fields worldwide.

The application of surfactants to improve oil recovery in conventional reservoirs via wettability alteration and enhancement of spontaneous imbibition has been extensively studied in the literature. However, little work has been performed yet to investigate the interaction of these surfactants with ultra-tight oil-rich shale reservoirs such as Wolfcamp shale. The use of horizontal drilling and massive multistage hydraulic fracturing has made primary oil recovery from these ultra-tight oil-rich shale reservoirs possible. With declining production from existing shale wells, it is essential to explore potential "beyond primary" strategies in shale oil development. This paper analyzes the potential of surfactants in altering wettability and improving the process of spontaneous imbibition in oil rich shales demonstrating nanodarcy range permeability, relevant to stimulation and "beyond primary" chemical EOR applications in shales. Novel proprietary surfactant blends along with traditional nonionic surfactants were investigated in this study using Wolfcamp shale core samples exhibiting nanodarcy permeability. X-ray diffraction analysis was performed which indicated that Wolfcamp shale has mixed mineralogy, with quartz, calcite, and dolomite acting as the major minerals in varying proportions depending on the interval depth. Contact angle and interfacial tension measurements were performed at reservoir temperature to identify the state of native wettability and the impact of surfactants in altering wettability. Thereafter, spontaneous imbibition experiments were performed using 3D computed tomography methods to understand the improvement in the magnitude of imbibition penetration due to surfactant addition. Contact angle and spontaneous imbibition experiments showed that Wolfcamp shale is intermediate-wet and surfactants have the potential to alter the native wettability to a preferentially water-wet state and improve oil recovery due to enhanced spontaneous imbibition. Surfactants which altered the wettability significantly, but lowered the interfacial tension only slightly showed the highest oil recoveries due to the creation of strong capillary driven forces directly responsible for effective spontaneous imbibition. The potential of surfactants in altering wettability and improving oil recovery via enhanced spontaneous imbibition in ultra-tight oil-rich shales was verified in this study. The effectiveness of traditional nonionic surfactants in altering wettability and improving oil recovery was found to be comparable to that of novel, more expensive proprietary surfactant blends, and hence, the traditional nonionic surfactants provide a cost effective option for stimulation and EOR applications in Wolfcamp shale. Overall, this paper presents the theory behind surfactant interaction with ultra-tight shales and provides experimental results to validate the viability of surfactant induced improved oil recovery in shales.

Upscaling of unstable immiscible flow remains an unsolved challenge for the oil industry. The absence of a reliable upscaling approach greatly hinders the effective reservoir simulation and optimization of heavy oil recoveries using waterflood, polymer flood and other chemical floods, which are inherently unstable processes. The difficulty in upscaling unstable flow lies in estimating the propagation of fingers smaller than the gridblock size. Using classical relative permeabilities obtained from stable flow analysis can lead to incorrect oil recovery and pressure drop in reservoir simulations. In a recent study based on abundant experimental data, it is found that the heavy-oil recovery by waterfloods and polymer floods has a power-law correlation with a dimensionless number (named viscous finger number in this paper), which is a combination of viscosity ratio, capillary number, permeability, and the cross-section area of the core. Based upon this important finding as well as the features of unstable immiscible floods, an effective-finger model is developed in this paper. A porous medium domain is dynamically identified as three effective zones, which are two-phase flow zone, oil single-phase flow zone, and bypassed oil (isolated oil island) zone, respectively. Flow functions are derived according to effective flows in these zones. This new model is capable of history-matching a set of heavy-oil waterflood corefloods under different viscosity ratios and injection rates. Model parameters obtained from the history match also have a power-law correlation with the viscous finger number. The build-up of this correlation contains reasonable physical meanings to quantitatively characterize the upscaled behavior of viscous fingering effects. Having such a correlation enables the estimation of model parameters in any gridblock of the reservoir by knowing the local viscous finger number in reservoir simulations. The model is applied to several heavy-oil field cases with waterfloods and polymer floods with different heterogeneities. Oil recovery in water flooding of viscous oils is overpredicted by classical simulation methods which do not incorporate viscous fingering properly. Simulation results indicate that the new model reasonably differentiates the oil recoveries at different viscous finger numbers, e.g., lower injection rate leads to higher oil recovery. In contrast, classical simulations obtain close oil recoveries under different injection rates or degrees of polymer shear-thinning, which is apparently incorrect for unstable floods. Moreover, coarse-grid simulations using the new model are able to obtain consistent saturation and pressure maps with fine-grid simulations when the correlation lengths are not smaller than the coarse gridblock size. Furthermore, it is well captured by the model that the shear-shinning polymer solution can strengthen the fingering in high-permeability regions due to increased capillary number and viscosity ratio, which is not observed in waterflood. As a whole, the new model shows encouraging capability to simulate unstable water and polymer floods in heavy oil reservoirs, and hence can facilitate the optimization of heavy-oil EOR projects.

This paper reviews the recently concluded first Near-Balanced Nitrified Stiff Foam application for a fractured low pressure reservoir formation; Sui Main Limestone in the Baluchistan region of Pakistan. The SML formation has presented extreme drilling challenges in this field. Severe loss circulation and reservoir influxes have made drilling this formation a night mare for the operator. Lot of Non Productive time has been spent while trying to pass through this formation. A recent application of the unconventional and innovative technologies has provided the client with an excellent solution. The major scope of work for this well is to pass the SML formation without having loss circulation and reservoir influx into the well bore while keeping good drilling performance and finally case the complete formation in one casing. A brief history of the Near-Balanced Drilling Technology using the Nitrified Stiff Foam fluid is provided in this paper which is followed by a discussion of the remarkable results achieved in this well. While performing the job the loss circulation problem was totally eliminated. Near-Balanced condition was constantly being monitored and maintained throughout the operation that resulted in no inflow from the reservoir into the well bore. Stiff Foam application also resulted in gaining outstanding drilling performance. All this resulted in the drilling of this formation in time less than half of the planned days. Finally the complete formation was cased within one casing without any complication. In Summary; application of the state-of-the-art and advanced technologies helped operator to eliminate the NPT associated with the drilling of this challenging formation. The operator was not only benefited with the rewards of this application but it also helped it to perform the Post Drilling operations in controlled, safe and desired manner. This paper reviews the process that was used to identify, plan, and implement these unconventional techniques. The purpose of this paper is to highlight all the benefits and lessons learnt while performing this first Nitrified Stiff Foam Near-Balanced Drilling mode application in Pakistan. This will help many operators in the designing and implementation of such techniques to challenging hydrocarbon bearing formations.

Water injection is one of the methods for maximizing oil production and improving oil recovery by way of maintaining reservoir pressure. It entails injection of water in sufficient quantities with acceptable quality into the appropriate zones of the reservoir in a cost efficient manner. Treated water is transmitted from treatment to well generally through carbon steel pipelines; as there are flexible pipelines, internally coated pipelines being used for water injection also. And this paper is solely for carbon steel pipelines. The corrosion of these water injection pipelines is a major issue for the Oil & Gas industry with a view to preserve the reservoir permeability and integrity of the pipelines. A few case studies pertaining to failure of API 5L carbon steel subsea water injection pipelines with their root cause analysis are presented in this paper. In order to identify the cause and mechanism of failure, detailed laboratory and analytical investigations were carried out with a view to characterize the material property as well as to evaluate the corrosivity of operating environment. Studies like visual inspection, non destructive testing, corrosion product analysis, elemental compositional analysis, metallographic investigations, inclusion content test, hardness testing, tensile strength studies, impact test, stereomicrscopy, scanning electron microscopic (SEM) coupled with energy dispersive spectroscopy (EDS) studies, have been carried out. Process parameters, operating & maintenance practices, chemical treatment program with quality parameters etc. have also been critically examined. Pipeline material was found to conform to the specification API 5L. The analysis showed that the most probable cause of the failure of the pipeline was under-deposit/grooving corrosion, which started with oxygen and Microbiologically Influenced Corrosion due to Sulphate Reducing Bacteria and was subsequently supported by very low flow velocities in those pipelines. The stagnant water and the formation of thick deposit consisting of corrosion product, sludge or suspended solids and biomass as a result of proliferation of bacterial colonies were the conditions for attack to set off. Galvanic corrosion further accelerated the metal loss process as grooving/channeling resulting into failure at 6 O'clock position. Presence of large number of inclusions in some of pipeline materials was an additional cause of accelerated corrosion process. On the basis of root cause failure analysis, the major integrity threats to the water injection pipelines resulting from process control were identified. Accordingly, preventive and remedial measures essential for preserving integrity of water injection pipelines have been suggested. Implementation of good operating and maintenance practices, robust quality control measures, continuous monitoring of corrosion trends, prompt corrective actions are the key requisites to abate failures due corrosion.

Most shale plays have to be hydraulically fractured to acquire commercial production. Shales are typically characterised by varying quantities of clay, carbonate and organic material, therefore each shale type has different deformational properties, which lead to different outcomes with respect to hydraulic fracture efficiency. Unconsolidated, high clay content or organic rich shales exhibit visco-elastic or visco-plastic behaviour, acoording to many researchers[1–3]. Although the effect of this time-dependent behaviour on fracture propagation is considerable it has not yet received much attention. The aim of this paper is to address the time-dependent response of shale under hydraulic stimulation, more specifically, to monitor fracture parameters change and deformation at crack tip area depending on the lag time between stress and strain.In this paper, an innovative method to analyse time-dependent deformation of material at fracture tip and its effect on propagation of hydraulically induced fractures by incorporating visco-elastic behaviour is presented. To characterise fracture state, J integral is revised and implemented in the framework of finite element model. The fracture is treated explicitly with refined mesh around the crack tip in order to obtain detailed information in static state. During loading condition, visco-elasticity and visco-plasticity is not differentiated for practical purposes.The results show that under a centain hydraulic pressure a crack creeps rapidly and possibly propagates. It is shown that stress intensity factor and revised J integral has a rapid changing gradient at the beginning and becomes stable over time. The crack tends to be wider and shorter in creeping shale. Propagation process is hindered by viscous energy dissipation and successive cohesive force. In simulation the experimental data from US shale plays are used to study fracture propagation behaviour under viscoelastic behaviour. Results of this study allow industry gain a better understanding of deformational behaviour of shale when fracturing. The know-how derived from this study will assist planning effective stimulation program in the development of shale gas reservoirs.

The pdf file of this paper is in Russian. The English version of this paper, IPTC-17269-MS, was presented at theInternational Petroleum Technology Conference held 19–22 January, 2014, in Doha, Qatar. Abstract With a step out distance of 170 km and a design power of 55MW, Martin Linge offshore gas field, will be the longest AC submarine cable power supplying an entire offshore Oil and Gas platform from the shore. This field development comprises a platform with a jack up rig and a Floating Storage Offloading unit. This paper discusses the criteria to consider and select a power from shore concept instead of an offshore Gas Turbine power plant which is the current practice in the offshore Oil and Gas industry. Since in a first approach, for such long step-out distance, the choice of power from shore would be to select a DC transmission line, the paper discusses the design and the main technical challenges of this long step-out AC transmission development. Finally, the system approach, required for the development of the onshore and offshore part of the project, is described. Introduction Discovered in 1975, Martin Linge offshore gas field (formerly named Hild) and located in the North Sea will be operated by Total Norge which has chosen to base this development with a power from shore concept. The facility will be designed for remote control from Total Norge onshore base in Stavanger (Norway). The field will be developed with a subsea installation and topside facilities. The processed gas will be exported to Total St Fergus terminal in UK via a new link to the existing Frigg UK Pipeline (FUKA). The oil, water and condensates will be processed and stored on a dedicated FSO storage vessel where water will be separated for reinjection, and oil will be exported via shuttle tankers. With a step out distance of 161km and a design power of 55MW, this will be the world's longest AC submarine cable power supplying an entire offshore Oil and Gas platform from the shore. This paper discusses the criteria which have been considered to select a power from shore concept instead of an offshore Gas Turbine power plant which is the current practice in the offshore Oil and Gas industry. Since in a first approach, for such long step-out distance, the choice of power from shore would be to select a DC transmission line, the paper discusses also the design and the main technical challenges of this long step-out AC transmission development. Finally, the paper underlines the electrical design particularities of this development and gives an operator's viewpoint as to the way forward. Project presentation The Martin Linge Field (formerly named Hild), is located on the Norwegian Continental Shelf, 75 km North of Frigg, 42 km West of Oseberg, 87 km North-East of Bruce, and 38 km South-East of Alwyn North field. TOTAL E&P Norge is the operator (49%) with Petoro (30%) and Statoil (21%) as partners. The Martin Linge field is one of the largest un-developed gas discoveries in the North Sea. Discovered 30 years ago, and operated today by Total E&P Norge AS, the field consists of several faulted and segmented gas condensate accumulations in the mid-Jurassic Brent group. The field also includes the Frigg oil reservoir which is a viscous, thin oil accumulation overlain by a small gas cap. Production is expected to be ~ 100 kboepd peak after start-up in quarter 2016, with ~ 70 kboepd during gas plateau. The total reserves are expected to be 176 Mboe. The production drive mechanism for the Hild (Brent) wells will be pressure depletion, i.e. no injection wells are planned for reservoir pressure maintenance. Frigg oil wells will be artificially lifted with gas lift. The produced water will be re-injected into the Frigg reservoir aquifer (not needed for pressure support).

The oil and gas industry in Russia started facing a complex problem of productivity decline from horizontal multi stage fracture completed wells drilled in the low to mid permeability reservoirs. To enhance hydrocarbon flow from these formations, aggressive production using artificial lift is supported with active water flooding. Nevertheless, operators have acknowledged that the horizontal well multi stage fracture (HW MSF) completions do not live to their expectations.The application of HW MSF completions started in 2008, but widespread acceptance followed several years later. Today, in Russia, about 300 horizontal wells are drilled and completed annually bringing the total number of HW MSF to more than 1200 wells. All these wells are potential candidates for re-fracturing treatments and re-completion, but while re-fracturing of vertical wells is a well proven success in Russia, the industry today has no clear understanding how to address the multitude of potential productivity difficulties in HW MSF.During the work published in this paper, the team has analyzed all the known potential engineering problems and technical risks and clearly defined the domains of further investigation and set recommendations on measurements that are needed to understand the impact of re-fracturing. The analysis was based on field measurements made, analytical calculation and numerical simulations, modeling in all details the key processes defining the productivity of HW MSF completions. The results indicate that pressure influenced stress changes in a mostly isotropic system and resulting fracture placement within the horizontal wellbore are key contributors to the complexity of the problem.The paper presented here is a genuine attempt for the industry streamline further search for solutions and novel methodology to effectively re-fracture the existing completion systems and bring these wells to profitable production.

Preventing and curing fluid losses in limestone formations is one of the most challenging loss situations to prevent and control. Loss zones are unpredictable, due to large vugular zones and extended and connected fracture structures. Often these limestone intervals are depleted reservoirs. Typically, calcium carbonate pills containing various size distributions are part of the lost circulation armory in reservoir sections. However, results are highly variable and not suitable for large-scale losses. This is distinguished for those situations with the most-severe lost circulation, where chemical sealants may be more applicable than treatments by plugging particles. The paper discusses about use of a cross-linking polymer fluid treatment that enables operators to cure lost circulation zones in many different applications, providing distinct operational and economic advantages over conventional reactive and temperature activated methods. The paper discusses the customization of the polymer fluid to have specific thickening or setting time so this loss circulation fluid can be pumped through the existing bottomhole assembly (bit nozzle size greater than 14/32nd) without losing rig time associated with tripping and mixing conventional loss circulation material treatments (LCM). The paper discusses the execution procedures and cautions to be followed to improve cross-link LCM plug placement as well as chances to arrest losses. Due to biodegradable nature of organic cross-linking polymer plugs, it was used in sensitive reservoirs with minimal effect on the formation. The cross-linked plug or pill, with time and temperature, will break back to a fluid state and may be produced back and circulated from the wellbore. The discussions in this paper will further reveal the workings and applicability of cross-link polymer fluid to lower costs for drilling fluids, cementing and casing design.

Multi-cluster staged fracturing is an effective method to exploit shale gas. Field observations reported some clusters did not generate fractures. X formation in Sichuan Basin is a 3000m deep shale reservoir. The horizontal stress ratio (Shmax/Shmin) is around 1.4 which is therefore difficult to generate fracture network. How to enable all fractures propagate effectively from each cluster and generate enough stress interference to enable fracture network is of critical concern. This paper established a 2D fracture propagation model based on finite-element method to simulate multi-cluster fracturing. The fracture propagation model couples seepage-stress-damage theories to simulate fracture propagation. The cohesive element is used to simulate the forming of fracture, and the filtration from fracture to matrix is taken into consideration. This model is used to study three fractures propagating simultaneously from three clusters. Different cluster spacing cases were simulated to investigate the fracture geometry and the stress field. When the cluster spacing is 10m, 20m and 30m, the simulation shows that the length of the middle fracture is severely restricted; but for the side fractures, the length is over propagated. When the cluster spacing is 40m and 50m, balanced propagation of all the three fractures is achieved. In 10m, 20m and 30m cases, the stress field shows that in front of the middle fracture, there is a high compressive stress area caused by over propagated side fractures, and this stress could prevent the middle fracture from propagating. So the range of optimized cluster spacing is reduced to greater than 40m. In order to increase the possibility of generating fracture network, the cluster spacing should be small to create high rock frame stress between the fractures. By considering the fracture geometry and stress field, the optimized cluster spacing is 40m cluster. This paper presented a method to optimize the cluster spacing by both considering the fracture geometry and stress field. Cluster spacing optimized by this method could enable the effective propagation of all main fractures and increase the possibility of generating fracture network.

This paper illustrates varying situations where the high-expansion hanger has proven to be a viable and valuable solution for reservoir analysis and optimization. Difficulties associated with acquiring accurate data using modern completion designs or new exploratory methods to optimize producing resources are also discussed in addition to solutions provided using the high-expansion hanger. A new high-expansion gauge hanger is deployed on slickline or coiled tubing using a non-explosive setting tool, for completion and reservoir analysis during well testing. It can be positioned anywhere in the casing for through tubing and/or rigless operations. The high-expansion design provides a generous bypass flow area to increase accuracy of data recorded. A unique slip design enables reliable set in highly scaled or corroded pipe. Precise placement of downhole gauges on slickline reduces cost and improves accuracy of reservoir and production analysis for improved recovery and efficient well placement. It is becoming more important to ensure the accuracy of reservoir performance data acquisition to maximize asset production and extend the life of the well. By using strategically placed sensors to accurately record critical information from multiple forms of testing and reservoir enhancement techniques, accurate data gained during testing phases ultimately leads to the best flow regime design and successful reservoir optimization. Modern completion design or reservoir stimulation techniques are effectively evaluated using data acquisition, aiding the development, refinement, and implementation of such techniques. Anchoring sensors in wellbores without decreasing flow can be challenging when introducing new techniques or modifications; these flow-rate conditions can prevent the determination of production at the time and rate that could maximize production and revenue of the asset. This paper examines difficulties associated with accurately acquiring downhole pressure and temperature data in complex well completions as a means to analyze reservoir properties and ultimately optimize the asset recovery. The high-expansion hanger provides a means for precise placement of downhole sensors in more challenging completions during well testing. Being able to precisely position pressure gauges, sampling tools, or other memory-based logging mechanisms is of great value. By using the slow consistent power of the downhole electrical power generator tool as a setting tool, the gauge hanger provides increased reliability and creates a secure anchor point, regardless of scale buildup or location. It can be run on slickline, electric line, or coiled tubing (CT), providing multiple solutions.

After billions of years of evolution, creatures in nature exhibit almost perfect structures and functions. Through learning from the nature, human beings are now able to develop biological multifunctional materials which can be applied to the engineering fields[1-5]. This paper focuses on foamed Nickel with bird-bone structures, which has advantages such as low density, high strength, controllable porosity, strong sand-containing capacity, and oil/water separation ability, etc. Previously, we have applied bionic Nickelfoam to down-hole sand control[6]. The open pore substrate has a very permeable structure, the porosity and the pore size of the metal foam can be varied in a large range to meet the sand control demand. The open pore Nickel foam is wrapped around a cylindrical geometry perforated base pipe. Sand bodies would settle inside the foamed metal after entering into pores without blocking thanks to the 3D characteristics of the porous structure. The number of foam layers and the pore sizes can be varied in order to achieve optimum flexibility for different sand control applications. Recently, in order to separate oil and water, the Nickel foam has been modified chemically. This paper demonstrates its superior properties in terms of special wettability, buoyancy, and corrosion repellency. Furthermore, high separation efficiency and long-term repeatability of oil/water separation can be reached according to a series of tests.

One of the main challenges of drilling in the Central Andaman Sea offshore Myanmar is the mitigation of overall well integrity risk arising from weak top-hole formations. On a well drilled by one operator, conductor integrity was lost due to cratering and loss circulation while cementing which eventually led to having to re-spud the well. Almost all the offset wells drilled by the operator in the same field experienced losses in the top section interval. To meet integrity objectives for both exploration and development wells, the cementing strategy in certain cases must consider alternative solutions in addition to conventional Class G cement. In a recent project executed for one operator the cementing philosophy for the entire surface sections therefore had to be fine-tuned to incorporate the proven Optimized particle-sized distribution methodology. A proprietary coarse material made from glass beads was introduced as part of the slurry design, being used for the first time in Myanmar to further improve cement properties. On the development wells the optimized design called for pumping 10.5ppg High-performance Light-weight cement (HPLWC) lead slurry, together with a standard Class G tail. To meet operational integrity objectives, planning and risk assessments were put in place by the service company and the cementing programmes were developed to incorporate necessary mitigations against the identified risks. Plans were put in place to handle the implicit logistics requirements. Careful attention was paid to the execution given the downhole pressure sensitivities, all slurries were mixed and pumped with a degree of relative precision. This paper summarizes the design and implementation of the cementing operation which contributed positively to meeting well integrity objectives. Apart from operational success, expectations which hitherto factored in possibility of top-up jobs were exceeded; for the exploration well the critical zones were covered with good returns to seabed observed on all the cement jobs as monitored by ROV. Hard cement were tagged and drilled out from the shoe track in each case and well operations progressed without any loss of integrity issue. The paper aims to demonstrate that incorporating technology can help to improve well delivery and reduced lost time. Approximately, 18 cement jobs have been executed on the project - all successfully done. Out of these 4 top-hole cement jobs involved the use of the High-performance Light-weight (HPLWC) technology described in this paper.

The effects of the earth's tectonic movements are well understood, especially in the formulation of stress anisotropy in a large region. This primarily mechanical effect stays unchanged because the support systems, such as faults, compressions, etc., remain unchanged until the next major tectonic activity. On the other hand, pressure effects are generally semi-permanent and are usually affected by the production history of the formation. In this stress domain, fracture placement during a stimulation treatment will always follow the direction of maximum stress; by definition, this is a fixed direction defined by the known stress anisotropy landscape.This paper presents a different approach for the stimulation process. Instead of a conventional, static, or end-point vision of the stimulation, a dynamic, or temporary, time-dependent stimulation method is introduced. The new method creates a small tectonic motion—significantly smaller than that of natural tectonics—and uses it to temporarily modify the local stress anisotropy. The "micro" tectonic motion is created by means of a conventional fracture placed in the natural maximum stress direction. Another fracture can then be created using the same approach but in a temporarily modified stress field that forces it in a different fracture direction. This new multioriented hydraulic fracture (MOHF) stimulation method can enhance state-of-the-art hydraulic fracturing technology by requiring an understanding of the transient geomechanic response in the treatment area.As a time-dependent method, this approach can create new opportunities in both conventional and unconventional plays by providing connectivity to previously unattainable locations in the formation. Unfortunately, it can also result in new complications. Industry standard fracture simulation technology becomes incomplete, as most models neglect the transient response of the system. Additionally, the availability of data related to the dynamic behavior of rocks is limited. The dynamic compression of the rock, slip characteristics between rock layers, and the amount of energy stored within slip planes—all recorded as a function of time—are particularly important when considering an MOHF process. Additional testing should be performed to obtain these data. With such data, time-sensitive operational recommendations for performing the MOHF stimulation can be provided to help achieve the maximum production increase from the well.This paper also discusses a computational validation of the MOHF process. As traditional hydraulic fracture simulations are derived using static formation properties and steady-state assumptions of the formation behavior, a unique transient three-dimensional (3D) computational geomechanic fracture simulator was developed to perform this study. The new model incorporates cohesive zone elements to represent the fracture plane and captures the dynamics of fracture initiation and propagation, as well as the transient stress modification in the formation. A realistic 3D fracture transient behavior is accounted for by the inclusion of multiple rock layers in the model, which are connected through energy absorbing frictional elements. Production levels of two to five times greater were predicted using reliable production simulators.

In this paper a five spot well patterns is used to study Low Salinity, Polymer, Conventional, Water-flooding and the combination of Polymer flooding and LSWF. The aforementioned cases are applied under different wetting conditions. Oil recovery is a function of reservoir forces. Effective IOR implementation requires the proactive identification and contribution of the dominating reservoir forces, over the course of the field development. The work in this paper uses a validated, compositional simulator in addition to validated relative permeability and capillary formulations to simulate LSWF, PF, Conventional, Water-flooding and combination of PF + LSWF in a multi-dimensional, anisotropic and aerially heterogeneous model, under various wetting conditions. Wettability modification is also simulated using start and end relative permeability, captured and validated from literature.The initial wetting state is an important criterion for LSWF. The incremental recovery in oil-wet systems, or "typical carbonate reservoirs," is more rapid and thus requires less dilution of the injected brine salinity. In addition, simulation results indicate substantial un-swept quantities of available oil saturation. Therefore, the role of polymer flooding is examined along with conventional water-flooding in wetting conditions where LSWF may not achieve significant incremental recovery. LSWF is not effective in intermediate wetting conditions and Polymer flooding yields higher recovery factors in all water wet conditions.The impact of reservoir damage has an adverse effect on the development's recovery factor and polymer flooding yields the highest incremental recovery in case of low permeability formations. In oil wet conditions the performance of PF and LSWF is similar especially in weak oil wet systems due to the equal contribution of their respective displacement efficiencies. In strong oil-wet conditions the combination of PF + LSWF yields the highest recovery factor. The wetting conditions, formation heterogeneity and permeability magnitude all impact IOR selection and suggest that each oil reservoir has a unique ionic environment that changes naturally and by human intervention, therefore it is important to study different IOR methods at different stages of the field development.

Since physical parameters of CO2 are affected heavily by temperature and pressure, including density, specific heat capacity, thermal conductivity and viscosity, the calculation of wellbore temperature distributions during CO2 fracturing is different from hydraulic fracturing, in which those physical parameters are regarded as constants. In this paper we consider those physical parameters as variables in order to get more precise distributions of wellbore temperature during CO2 fracturing management. A wellbore temperature distribution model during CO2 fracturing process is established in this paper. The math model is based on the energy balance equation and the momentum balance equation and solved by finite difference method. In the calculating process, we considered the effects of temperature and pressure on physical parameters of CO2. Span-Wagner model and Vesovic model are used to calculate those parameters including density, specific heat capacity, thermal conductivity and viscosity. MATLAB is used here to implement those algorithms. Data of H79-31-45 well, a liquid CO2 fracturing well in Ji Lin-Field, is used to compare the calculated temperature with the measured data. This well use 0°C liquid CO2 as fracturing fluid to fracture the formation in depth of 1600 meters. The result shows that in the depth of 1000m and 1600m where the detectors are located, the relative errors between calculated data and measured data are less than 2% both at the beginning and the ending of the management. And as the injection time increases, the temperature of the wellbore has a significant decline, which illustrates very good agreement with result of the calculation. It indicates the precision of the simulation satisfies engineering requirement. In general, since the established model has a high accuracy, sensitivity analysis can be undertaken to analyze the effects of different parameters like the injection rate and injection time on wellbore temperature and the results can provide insights for designing fracturing schemes.

This paper describes the first known offshore application of distributed horizontal pulse testing. This technique appraises the deliverability of naturally fractured resource, using only a single penetration and Drill Stem Test (DST) string run. Central to the design is the ability to collect near real-time interference data at a known minimum length from a drawdown interval. The pulse test is distributed in that the signal and observation zones can be swapped on demand from surface, acoustically via sleeve. BP successfully applied this technique to two appraisal wells in their 2014 offshore drilling operations. The dual zone DST pulse testing method is a new approach to the appraisal of naturally fractured reservoirs. It was developed to create a real-time interference dataset outwith the active production interval, i.e. within a passive zone. The formation is produced (and rate data are measured) in two spatial locations and across two known length-scales (by swapping the active and passive zones prior to commingling). Pressure diffusivity can thus be calibrated to data measured in two spatial locations of the same reservoir, and not just one, as per a conventional test design, i.e. enabling a history match of the pressure response of two lateral zones from a pulse signal in one. The horizontal aspect is achieved via high-angle well, drilled sub-parallel to unit bedding (Figure 1). With the double staging approach (upper and lower zones), which has been developed for fractured reservoir appraisal studies, three tests were successfully performed in each appraisal well: two partial penetration tests on discrete short intervals (DST#1a, DST#1b), and one final test on a longer interval that included both of the short intervals (DST#1c). Results of this application have demonstrated that pressure diffusivity can be derived from pressure data that are measured simultaneously in two spatial locations, within and outwith an active production interval. This has proved particularly useful for reducing the degrees of freedom in reservoir model identification. The paper concludes that appraisal of naturally fractured reservoir might be sub-optimal in a DST design where drawdown and observation data are limited to a singular inflow zone only. This is the first known application in the industry where one DST run has successfully yielded six unique appraisal data types, gathered simultaneously at both intra/inter zone and commingled length-scales. These data are conventionally not gathered in a single zone design, i.e. without the ability to selectively inflow and monitor pressure in each discrete lateral zone. Consequently this technique has significantly improved the description of both static and dynamic reservoir properties and reduced development uncertainty, all at a relatively low incremental cost.

The analysis of string stability affected by earthquake in the shallow of deepwater drilling In deepwater drilling, wellhead, catheter, surface casing system and riser are linked together, they show the characteristic of instability under the influence of wave force. Some scholars have already done some research on this topic, however, the shallow sea is an area with frequent earthquake. Especially in some active seismic zone, oil and gas are often accompanied by earthquake, so it is crucially important to study the seismic forces on deep-water shallow wellhead, catheter and surface casing. On account of the dynamic pile soil, the paper firstly studies the classification of the shallow soil properties. The paper carries on an overall study as landing depth of surface casing is about establishes the neural network model, considering the length, diameter, vertical pressure, casing pipe weight, soil properties, pore pressure, shallow properties of drilling fluid and especially the seismic characters of surface casing string. The influence of earthquake on the casing string stability will be gotten from these data collected after neural network analysis and calculation. Based on the geological characteristics of Yingqiong basin, this paper establishes the neural network input and output bridge, obtains the earthquake effect on shallow casing string, and get the following conclusions: 1. Natural environment and other factors have certain effects on the casing string stability; 2. Traverse force on casing string increases by the earthquake action; 3. The earthquake has greater influence on the wellhead stability; 4. Shallow casing string vibration frequency can be obtained during earthquake action. Study of Vibration of casing string in deep-water has been the difficulty of research. As many accidents happened due to multiple factors, shortages in current study, it is particularly important to research on how to build a deep shallow casing string vibration model, especially considering the uncertainty of seismic force. Importance of this paper is the further study of the influence of the seismic force.

In thermal recovery from unconsolidated oilsands reservoirs and in association with fluid mobility, formation compressibility and modulus of elasticity are closely related to pressure transient and stress redistribution behavior, which can collectively affect the steam chamber development. The non-linearity and stress-dependency in bulk compressibility and modulus of elasticity of rocks has been captured through the development of elegant constitutive models (e.g. nonlinear elastic hyperbolic model) and has been readily integrated into coupled reservoir-geomechanical simulation packages. To assess the significance of these nonlinearities for reservoirs with different initial stress states, this paper presents an analytical study where the associated impacts on the redistribution of stress (stress-paths) and the onset of geomechanical mobilization (shear dilation) under the assumption of uniaxial deformation are quantified. Within the scope of this paper, (semi-) analytical modeling is conducted while special attention has been devoted to (1) the vast range of depths of the existing oilsands reservoirs and the associated implications on the initial stress distribution as well as stress redistribution due to steam/water injection, (2) the impacts on the onset of geomechanical mobilization within the practical ranges of injection pressures, and (3) the evaluation of geomechanical mobilization potential for thermal (steam injection) versus non-thermal (cold water injection) pressurization. The results show that (1) the potential impact of stress dependency on the variability of the geomechanical properties (modulus of elasticity, Poisson's ratio and formation compressibility) is more significant for shallow reservoirs as compared to mid-depth and deep reservoirs, (2) the injection pressure required to onset the geomechanical mobilization may be under/overestimated if the non-linearity in the mechanical properties is overlooked, and (3) the thermal geomechanical mobilization (steam injection) may have a higher potential within practical ranges of operating pressures as compared to non-thermal techniques (cold water injection), especially for shallower reservoirs. The inherent limitations of the analytical workflows as well as the requirements of supporting efforts through coupled reservoir-geomechanical simulations are also discussed.

This paper investigates the effect of anisotropic behavior of caprock shales on the caprock failure pressure in SAGD projects. Shales and mudstones exhibit strong anisotropy at the micro and macro scales. However, the anisotropic behavior has been neglected in the existing published works on this subject. In this research project, a coupled hydro-thermo-mechanical model was developed for the assessment of caprock integrity in thermal operations. A transversely isotropic constitutive model in the elastic range was combined with an anisotropic failure criterion to capture the intrinsic anisotropy of the cap shale. The coupled tool was validated against field data and employed in a study to determine the effect of shale anisotropic behavior on the pressure associated with caprock breach. Results display the effect of shale anisotropy on caprock response in terms of deformations, stresses and failure pressure. The assumption of isotropic shale behavior in caprock integrity assessment for a case study resulted in the overestimation of the failure pressure by about 10%. Existing numerical models for evaluating the integrity of caprocks during thermal operations employ isotropic constitutive laws. These models are believed to be deficient in capturing strongly anisotropic response of shales and mudstones. The research described in this paper incorporated elasto-plastic shale anisotropy in the caprock failure analysis model for the first time. The paper demonstrates the importance of capturing shale anisotropy in the accurate prediction of caprock breach pressure in SAGD projects.

Most conventional fracturing fluid systems are based on guar and guar derivatives. Therefore, fracturing costs are strongly influenced by guar price. In addition, when pumped in unconventional formations, these fluid systems can cause significant formation damage due to insoluble protein components in guar. While Polyacrylamide (PAM) based copolymers are often used in unconventional formation stimulation, they are often considered to be hard to break. A possible solution that can mitigate the problems associated with the conventional fracturing fluid systems is a new fluid system based on a carefully designed synthetic polymer. The synthetic nature of the polymer translates into a stable operating cost without being impacted by market fluctuations like in the case of guar. This new synthetic polymer system is crosslinked and applied similarly to polysaccharide-based fluids. To alleviate concerns that synthetic polymer is hard to break, this polymer incorporates special linkages, periodically distributed along its backbone, to make it easily broken into small fragments with conventional oxidative breakers under downhole conditions to leave minimal formation or fracture damage. The polymer also incorporates functional groups that resist damage from water hardness. In addition, the polymer hydrates almost instantaneously and allows rapid viscosity generation and adjustment without a hydration unit, which greatly reduces footprint of hydraulic fracturing treatments. While this new polymer system can be used in slickwater hydraulic fracturing and linear gel applications, laboratory testing also showed that it can be effectively crosslinked with conventional metal crosslinkers. This paper investigates the possibility of using this new polymer as a total package to be applied throughout hybrid fracturing operations for tight formations besides using it as fracturing fluids for conventional formations. Laboratory work also investigated other applications of the new polymer such as acid gelling, acid fracturing, and diversion, to name a few. This paper presents the laboratory performance and the underlying mechanisms of the novel polymer fluid system.

The Breagh gas field lies in the UK Southern North Sea, 100 km east of Teesside in Blocks 42/13, 42/12a and 42/8a. The normally-unmanned gas field came on stream in October 2013 and is the first offshore development of the Yoredale formation of the Lower Carboniferous. The reservoir comprises a mixture of sand sheets and channels with permeabilities predominantly in the range 0.1 to 10 md. The plan for the first phase of Breagh Field development was to drill 10 conventionally completed 65° angle deviated wells, through the reservoir, from a 12 slot platform. Analysis of log and PLT data from some of the initial wells identified channel sands, tighter than expected, yet containing significant GIIP. Wells 7 and 8 of the first phase of drilling were completed using hydraulic fracturing to evaluate the potential for improvement in productivity and drainage from the lower permeability intervals, although the execution of the stimulation programme brought significant challenges. This paper introduces the Breagh Field, discusses the reasons behind the change in completion design to include hydraulic fracture stimulation, considers the challenges associated with fracture placement in high angle wells and solutions implemented. The paper also addresses the importance of the clean-up phase, and reviews the lessons learned. In support of this programme, a number of hydraulic fracture designs and modelling methods were evaluated and used to make real time decisions during stimulation operations. These methods are discussed and used to estimate the value of hydraulic fracture stimulation in the Breagh field to date. The first two wells to be stimulated on Breagh have been successful, yielding initial increases in productivity of the order of 4–10 fold. The magnitude of this increase has led to a forecast of significantly higher recovery from the lower permeability sands and from the total field. Important learnings from the subsurface characterisation, fracture planning and execution phases have been made. As a result of the success to date, hydraulic fracture stimulation is being integrated into the well completion planning and facilities design for the next phase of Breagh Field development.

Hydraulic fracturing de-facto is the most common stimulation technique that is employed worldwide. Russia is following the same trend and most of the new and old wells are considered for hydraulic fracturing. However, eventually as more and more reservoirs become depleted operators are looking forward to formations with so called “hard-to-recover” deposits in order to sustain hydrocarbon production. These “hard-to-recover” deposits include: Unconventional shale pays similar to US – Bazhenov and Domanik formations.Caspian, Arctic, and Sakhalin offshoreEastern Siberia green fieldsMature fields and formations where conventional stimulation is not as effective as expected due to variety of reasons. This paper is focused on fracturing experience of mature fields. Our experience shows that post-fracturing well productivity for mature fields can be altered but not limited to several issues: It can be severely reduced in case of multi-phase flow inside the fracture due to non-Darcy effects when bottomhole flowing pressure is significantly below bubble point pressure.At the other extreme, heavy and viscous formation fluids lead to rapid fracture conductivity degradation due to proppant flowback. Excessive proppant flowback leads to the necessity of frequent wellbore clean-out operations, reduces lifetime of the artificial lift system and down-hole equipment. These conditions call for wider and more permeable fractures in order to obtain desired production rates and overcome negative geological features.Fracture breakthrough into a water layer also leads to ineffective stimulation.Well conditions such as cement bond and overall well aging. There are several technologies and techniques that could possibly be used (and used nowadays) to overcome cited problems, but most of them have applicability limitations. The paper is focused on first two – conductivity increase and fracture deterioration. One of the solutions that is capable to cope with conductivity related problems and proppant flowback issue and doesn't have application limits was found to be unconventionally rod- shaped proppant. In comparison with conventional round proppant, it provides higher fracture conductivity with integrated flowback control due to random alignment of proppant rods. Conventional method of proppant flowback control widely used in industry is resin coated proppant (RCP). Significant benefit of rod-shaped proppant over conventional RCP is that it does not have any limitations on bottomhole temperature and pressure as flowback prevention happens due to physical interaction between rods and not chemical bonding due to resin, does not require any chemical activation, chemicaly inert and, does not have special flowback requirements. Since the introduction of rod-shaped proppant in Russia in 2011, more than 90 fracturing treatments have been successfully carried out with this unconventional proppant inside the country. Well production analysis proved that rod-shaped proppant was more effective than conventional proppant. In most cases we observed productivity increase over conventional treatments. Further, no proppant flowback issues were detected on wells fractured with rod-shaped proppant. This paper is addressed to the experience of use of rod-shaped proppant in challenging mature low temperature reservoirs with high formation fluid viscosity.

Scale inhibitor squeeze treatments in unfractured reservoirs can be readily simulated in matrix flow models, designing such treatments for application in fractured reservoirs is less routine. One reason for this is that the flow process and transport mechanisms by which the inhibitors are retained in fractured formations differ considerably from simple matrix flow. In previous papers, we described a diffusion-controlled transport model for scale inhibitors in low permeability fractured reservoirs where little matrix flow is expected. In this paper, the model has been used to simulate squeeze treatments performed on multiple wells in a fractured shale formation and compared to simulations using a matrix flow model. A number of squeeze treatments were performed on wells in a fractured shale formation yielding long treatment lifetimes. The squeeze treatments were designed using a matrix flow model. Calculations indicated the design pumping rate would require an injection pressure significantly more than the fracture pressure for the formation indicating little matrix may possible for this case. The treatments were successful, however, the observed field return did not match the prediction and in some cases longer treatment lifetimes were observed. When a standard matrix flow model was used, the resulting field isotherms were significantly different for each well in the formation. This is taken to indicate that the matrix flow model approach is not accurately mimicking the field data. When the same data was examined using the diffusion based fracture model, a single isotherm was found to be a good match for all of the wells from the formation. In addition, explicitly modelling the varying water production rates in the diffusion model gave good correlation with changing trends in the return concentrations seen in the field return. Furthermore the possibility of improving the treatment lifetime is considered, factors such as the effect of the overflush volume and injection rate are discussed as treatment modifications and the influence may have on formation damage. Accurate prediction of squeeze treatment lifetimes is important for scale management both economically to ensure optimum productivity and practically to schedule treatments appropriately. Until recently this has not been achievable for fractured formations without the use of full field simulators. The paper illustrates that an appropriate near wellbore model can give good agreement with field data and has been used to design better treatments without the need for complex full field simulators.

The industry is exploring for oil and gas in reservoirs that contain in-situ corrosive fluids, such as CO2 and H2S. In addition, there has been a push to sequester the CO2 produced from various industrial sources. To this effect, geological carbon dioxide storage is an economically viable method to help reduce greenhouse emissions and CO2 injection is an effective enhanced oil recovery (EOR) method. Ensuring long-term safety and efficacy is one of the primary technical challenges in this context attributed to potential degradation of the cement sheath, creating pathways for leakage. Design of CO2-resistant slurries is an important mitigation approach. This paper discusses an experimental evaluation of the chemical effects of CO2 on key properties of cement sheaths. Twelve slurries were developed based on the two primary approaches to mitigate CO2 degradation: (a) reduction of reactive hydration products and (b) reduction of cement matrix permeability. This paper reports results for four selected slurries in a carbonic acid environment. Seven samples of each slurry were cured and then subjected to an aqueous CO2 environment (carbonic acid) for 15, 30, 90, 180 and 365 days. Downhole conditions were simulated by running the carbonation tests at 165°F and constant CO2 partial pressure of 2, 000 psi. At the specified time points, samples were removed to perform chemical tests (inductive coupled plasma [ICP], water analysis, X-ray diffraction [XRD], thermogravimetric analysis [TGA], and dye penetration) and physical tests (ultimate compressive strength [UCS], Brinell hardness, permeability, and porosity). The general observation was improvement in terms of physical properties up to 90 days, followed by a decrease that continued throughout the experiment period. Formulations mixed with NaCl brine were additionally degraded by salt leaching. The best resistance to degradation was obtained using formulations with reduced portland content and elastomers to reduce permeability. Higher compressive strength was correlated with low permeability. Most slurries had a permeability lower than 0.1 millidarcy (mD) after one year of exposure. Chemical testing supports the interpretation that the early improvement in physical properties can be attributed to carbonate precipitation, while later degradation is attributed to the formation and leaching of calcium bicarbonate. Some slurries contained sodium chloride in mix water at saturation levels. In which case, sodium chloride leached out of the cement sheath and was confirmed by water analysis. In the carbonic acid (wet) environment, a dense layer of calcium carbonate was observed that corresponded to an increase in Brinell hardness This study demonstrates the efficacy of a testing protocol that can be used to evaluate various cement blends for long-term integrity under downhole conditions and different forms of CO2 attack. The results were used to design cement systems more resistant to CO2 degradation than conventional slurries.

Making forward predictions of a pipeline's behaviour from an operational base state requires a working knowledge of the pre-existing stresses and strains. To gain this working knowledge for a pipeline that has undergone lateral buckling requires either an engineering assessment that can accurately predict the displacement of the pipeline on the seabed, and from which the operational stresses and strains can be estimated and extracted, or instrumentation on-board the pipeline that records stress and strain information which can be uploaded and sent back to the analyst. Whilst it is hoped that the pipeline analysis carried out in design stage be focused and accurate enough to capture and present the required data for life-of-field assessments the reality is otherwise. The purpose of the design strategy would have been to attain code compliance and the required safety level for the pipeline system, which are targets that may be at odds with predicting most realistically the pipeline's state in the operating condition. This is a result of the design needing to accommodate multitudinous conservative assumptions about the pipeline geometrical properties, the seabed profile, operating pressure and temperature profiles, as-laid out-of-straightness and pipe-soil axial and lateral resistances and also the need to attend to code requirements which will have their own partial safety factors embedded. It must be admitted, reluctantly, that the pipeline response realized in the field may never be an accurate reflection of the outcome of the design process. This paper presents data pertaining to the surveyed as-built configurations of deep water HP/HT pipelines and a small diameter piggyback pipeline and a method for making forward predictions from such pipelines about their observed base states. The information contained in the paper may be used as input to future design strategies or as key considerations for the successful completion of such re-analyses by other operators, contractors and consultancies.

This study develops the allowable suction pressure envelopes using applicable industrial codes for different suction pile sizes at various penetration depths. In addition to the industrial codes, 3D nonlinear finite element analysis (FEA) utilizing plate buckling techniques is carried out for comparisons. Traditionally, the suction pile design has considered very comprehensive soil failure mechanisms in general practice. However, the structural plate buckling criteria for suction pile with large D/t ratios are not well defined to reflect the current industrial codes and standards. This paper performs extensive study to investigate the buckling strength of suction piles with various D/t ratios using different industrial codes and standards. This study also proposes the 3D nonlinear FEA including the geometric and material nonlinearity and using the plate buckling technique in order to predict the buckling strength for piles with various D/t ratios. The above approaches can provide thorough comparisons among different code requirements and FEA results. After suction pile's self-penetration, the initial suction pressure required to mobilize the force penetration can be critical for pile shell buckling, especially for the large D/t and long pile. This required suction pressure due to moderate soil setup and static friction is briefly discussed in this paper. Based on this study, different codes and standards suggest different buckling strengths to the same pile. In general, for piles with D/t ratio less than 120 and with small L/D ratio, the suction pressure to fail the pile structure is much higher than that for the soil plug failure in regular clay soil; nevertheless, this may not be applicable for piles with D/t ratio greater than 120 and with large L/D ratio. The industrial codes and standards using thin wall theories shall be adopted to design suction piles w in order to take into account various structural buckling modes. For the 3D nonlinear FEA, the post buckling analyses predict the suction pile buckling pressures and show the reduction in pressure after buckling rather than traditionally selected buckling pressure at an arbitrary displacement regardless pile geometries. The proposed approaches to generate the allowable suction pressure envelopes can lead to an economical suction pile design and provide the installation contractor with a visualize tool to ensure a safe and successful suction pile installation.

This paper describes a GIS-based application of shear band propagation to model slope instability that combines rapid analysis over large areas using pixel-based analysis with an approach capable of modelling the observed slope failures. Slope instability modelling can be performed over large study areas through application within a GIS. This approach typically involves calculating the limit equilibrium factor of safety using an infinite slope geomechanical model for a dense grid of pixels covering the study area. The result is a quantitative and spatially resolute estimate of susceptibility to slope failure representative of the seabed gradient, sediment strength and density, and other conditioning or triggering factors. For input to a spatial risk assessment, factor of safety can be converted into annual probability of failure using a Monte Carlo assessment to capture the uncertainties in the inputs and the modelling approach. Shear band propagation offers an alternative to limit equilibrium and provides a simple approach to modelling to the long and relatively thin slope failures typically observed in the offshore environment. This method is applied probabilistically, resulting in a numerical map of annual probability of slope failure through shear band propagation. The complexities of applying a two-dimensional model within a three-dimensional spatial framework are explored in this paper. This GIS-based probabilistic slope stability assessment using shear band propagation has been successfully employed as part of a landslide risk assessment of the Azeri-Chirag-Gunashli (ACG) development, Caspian Sea, where pixel-based annual probability of failure estimates contribute to a landslide risk score for each geohazard province within the area.

In the design of Floating Production Storage and Offloading facilities (FPSO), it is important to predict the seakeeping parameters like FPSO motions. This paper focusses on the prediction of FPSO motions and wave impact loads in various irregular sea waves and proposes a Computational Fluid Dynamics (CFD) model. Accurate prediction of FPSO motions and wave impact loads requires the accurate prediction of wave kinematics. Waves generated by winds blowing over the water surface in real oceans are short-crested, so the dynamic responses of the moving structure will be very different in long crested and short-crested waves. In this paper, we have verified the pure propagation of oblique short-crested random waves in numerical wave tank with the analytical results, which serves as the basis of more complex analysis including ship hull interaction with waves.The proposed CFD model uses Multiphase Volume of Fluid Model (VOF) along with Six Degrees of Freedom Model (6DOF) to predict the hydrodynamic forces and the ship responses. Long crested and short-crested random waves are simulated in a numerical wave tank, where boundary conditions for free surface profiles and velocities are imposed at the velocity inlet boundary using Jonswap frequency spectrum and cosine-2s directional spreading function.Wave slamming loads and the structural responses depend on many factors, like sea state, FPSO speed, draft, wave heading angle, local structure etc. In this paper, we have analyzed the wave slamming on a moving FPSO for different sea states (unidirectional, multi directional with 45 deg and 90deg angular spread) and studied the resulting hydrodynamic forces and related structural interactions. Ship motions (heave, pitch and roll), vertical accelerations, pitch velocities, roll velocities and the wave impact pressures are compared among different sea states.

To meet the challenges from an unconsolidated, deep sea sandstone reservoir, this paper developed a stimulation and sand control method through fiber fracturing. The key points of the technology are as follow: (1) This paper developed instantizing guar gel fracturing fluid system based on seawater, which can be online mixed with in-situ seawater. Transport of fresh water will not be required for the new system, and the application of new fluid can save platform space. (2) The fracturing design was optimized with orthogonal analysis method to improve the stimulation effect. (3) Fill fiber and resin proppant into hydraulic fracture to form an artificial screen, preventing the fine sand production. This method had been applied in a low-perm unconsolidated deep sea reservoir. Before the fiber fracturing, the pilot well was shut off because of no production. After treatment, the production reached to 20m3/d, and no sands were found in produced liquid.

Water hammer, or more properly ‘liquid hammer’ simulations are commonly performed with transient simulation software. However, care must be taken in the setup of such simulations to assure good fidelity with the field operation being simulated. Of critical importance is the realization that a sudden pipeline shutdown has a symmetry where a pressure reduction (which can easily result in the creation of a vacuum strong enough to pull gas out of solution, followed by explosive recompression of that resultant gas phase) occurs at the inlet of the pipe equal in magnitude to the pressure surge at the outlet. Much can be done with ‘pencil-and-paper’ calculations, including a worst-case estimate of surge pressures using the Joukowsky Equation. This equation can be further modified to account for elasticity, as would occur, for example, in a tanker loading hose – in fact, this modification is essential to obtain the correct behavior from the simulation models. This paper presents transient simulations, along with comparisons to pencil-and-paper equations and theory, to come up with a best-practices approach to water hammer modeling.

The most frequent completion method used in deepwater Gulf of Mexico is the use of gravel pack with sand screens. These are used to minimize and possibly avoid any sand production in the production system. Sand production from subsea wells tied back to a host can be a significant detriment to the integrity of the subsea infrastructure as well as the processing facilities at the host location. Hence, it is important to have effective sand control measures as well as reliable methods to measure sand, if produced. This paper discusses three case studies where sand production occurred even with sand control measures in place. The discussion is focused on the challenges associated with detection and quantification of produced sand as well as its impact on the subsea and topside infrastructure. The cases are for a dry gas well, a gas condensate well, and a black oil well. All three cases are subsea tie-backs to different host facilities. In these cases, the sand detection methods used are intrusive and acoustic type sand detectors, as well as centrifuge measurements of the produced fluids. The challenges associated with these methods are discussed in this paper. It is concluded that, at least in one instance, the acoustic device is reliable in identification of sand production but unreliable for quantification of the sand volume. In addition to produced sand measurements, inspection measurements which indicate wall loss of piping at the arrival of the fluids to the host facility are discussed. An attempt has been made to correlate the wall loss from inspection with erosional model predictions. It is concluded that the uncertainty in measured data is significant and, to pursue such a correlation, improvement in sensor reliability as well as accurate sand production data is required.

This paper summarizes best practice cost-effective geotechnical design of high pressure high temperature (HPHT) pipelines, with an emphasis on HPHT lines in deep water, that are susceptible to lateral buckling and axial walking. It presents guidance on (i) tools for optimal geotechnical characterization of shallow seabed conditions along flowline routes and (ii) techniques to assess pipe-soil interaction parameters for input to pipeline structural modeling. Recent research into pipe-soil interaction measurement tools and analysis techniques has resulted in rapid advancements that are being quickly utilized in practice.Advanced pipe-soil interaction techniques, firmly rooted in soil mechanics theory and linked to the operational sequence of the pipeline through cycles of start-up and shut-down, are presented. They are used to demonstrate benefits that can be realized on typical projects to reduce pipeline walking predictions and the associated mitigation measures such as hold-back anchors. Recommendations cover the appropriate selection of characterization tools and analysis techniques based on project-specific requirements such as seabed geotechnical complexity, pipeline operating conditions, project timing, mitigation strategies for global stability and the desired approach to risk management and use of the observational method.The results, observations and conclusions presented in this paper represent the culmination of several years of research and development in pipe-soil interaction, as well as our experience on recent projects around the world where these techniques have been employed. The paper offers recommendations to guide both geotechnical studies and pipeline engineering work, and unlock benefits from maintaining close integration of these two disciplines through the design and operation of a pipeline.

The objective of this paper is to present the new Offset-Pontoon Semi-submersible (OPS) for use as a drilling and production platform. The new semi-submersible features pontoons that are offset to the outside of the columns which lends the vessel a low heave response and enables the use of top tension risers with dry trees. Other advantages of the OPS are a shallow quayside draft, a large payload capacity and the ability to operate in ultra-deepwater. The primary design challenge for dry-tree semi-submersibles is to make their heave motions compatible with the stroke range of existing riser tensioners. Increasing the vessel draft to reduce the heave motions is constrained by installation requirements and stability limits. However, vessel heave motions can be reduced by modifying the hull shape. The OPS has a longer heave natural period and a smaller heave response than a conventional deep-draft semi-submersible. The heave performance of the OPS was compared with a conventional semi-submersible using frequency- and time-domain analyses. In this paper we also present a design study of the OPS for dry-tree field development offshore Brazil. The vessel was sized to support thirteen top-tension risers and a 30,000 ton topside. The paper describes design of the vessel and its global performance. Focus of the study was the wellbay loayout and the tensioner stroke requirements. For the selected design case we found ram-style riser tensioners with a stroke range of 30 ft sufficient. Integration of the hull and topside by float-over is also described.

Owing to the complex distribution of stress directions around a salt body, accurate prediction of mud-weight window (MWW) for subsalt wells has presented a challenge to the industry for a long time. This paper presents a comparative study on methods practically used in calculating the mud-weight window of subsalt wells. Selected methods, which include the 1-D analytical method, 3-D numerical method, and the integrated 3-D method, are compared. A subsalt well section in deepwater GoM was chosen as a validation example. Both workflows of each calculation method and resultant MWWs obtained with each method are analyzed and compared. The TVD depth of the investigated subsalt well section is from 22,000 to 30,000 ft. The salt body's thickness along the wellbore trajectory is 20,000 ft, and its width is 18,000 ft. With seismic sectional data, an anti-cline structure is constructed accordingly at its bottom surface. Mohr-Coulomb criterion is adopted in the calculation of MWW. A 1-D solution of MWW is calculated with the geostress field derived from overburden stress along the trajectory. A 3-D solution of MWW is calculated with the stress values obtained with finite-element submodeling techniques. An integrated 3-D solution of MWW is calculated with the 3-D stress field obtained from the finite-element method and an analytical tool for MWW calculation along the trajectory without using the submodeling technique. Comparisons have been made between the results obtained with the conventional 1-D method, 3-D finite-element submodeling method, and the integrated 3-D method. Solutions obtained with the conventional 1-D method have missed the abnormality of stress distribution at the salt base and have smaller values of MWW compared to the other solutions. The solution of MWW obtained with the integrated 3-D method is very close to the one obtained with the finite-element submodeling method, but at only one-tenth of the time cost. With the validation example of the subsalt well section, a comparison of workflows and the resultant MWW's accuracy has illustrated the advantages and disadvantages of typical 1-D, 3-D, and integrated 3-D method for MWW calculation. The results presented in this paper can be used as a reference deciding on the best practice for calculating the MWW of subsalt wells. This work also presents an example of best practice.