This paper addresses lateral pipe/soil interaction behavior at the large displacements that occur with lateral buckling of a pipeline. Force-displacement-response models were developed by the Safe-buck joint-industry project (JIP) to replace the use of simple friction-coefficient approximations. Such simplistic models are unrealistic for modeling large lateral displacements or the building of soil berms that occurs with cyclic lateral loading. The models are based on large- and small-scale tests carried out by the Safebuck JIP on deepwater soils from the Gulf of Mexico and west Africa, as well as on kaolin clay. To this database was added project-specific test data donated by JIP participants. Four stages of pipe/soil interaction are considered: Embedment of the pipe at installation. Breakout during buckle formation on the basis of different levels of initial pipe embedment. Large-amplitude lateral displacement as the buckle forms. Cyclic lateral displacement influenced by the building of soil berms. While breakout loads have been the subject of much research and published papers on pipeline stability, there is little guidance on modeling lateral resistance at the large displacements experienced in lateral buckling. There is also little guidance on modeling subsequent large-amplitude cyclic behavior, which occurs with each shutdown and restart of the pipeline. New equations were proposed where appropriate, and recommended models for each part of the characteristic response were developed. These models provide a valuable basis for lateral-buckling design guidance. They currently are being applied by JIP participants on a number of projects in which pipelines are being designed for lateral buckling. Background of the Safebuck JIP The aim of the Safebuck JIP (Bruton et al. 2005) is to raise confidence in the lateral-buckling-design approach and to improve understanding of the related phenomenon of pipeline walking. Experimental work is being undertaken at the Welding Inst. on low-cycle fatigue-materials performance and at Cambridge U. on axial- and lateral-pipe/soil interaction. The JIP has been very well supported by the offshore industry. BP, ConocoPhillips, ExxonMobil, Petrobras, and Shell, as well as the U.S. Government through the Minerals Management Services, participated in Phase I, with installation contractors and suppliers represented by Allseas, JFE-Metal One, Technip, and Tenaris. Additional participants including Acergy, Chevron, Statoil, and Saipem have joined Phase II, which will run through 2005 and 2006.
Summary The permeability, pore pressure, and leakoff type interpreted from more than 1,200 diagnostic fracture-injection/falloff tests were collected in a database and statistically evaluated for four Rocky Mountain basins. The statistical analysis includes the range of observed permeability and pore pressure and the fracture leakoff type distribution. The analysis reveals that pressure-dependent leakoff, fracture-tip extension during shut-in, and fracture-height recession during shut-in are the most common leakoff types. Overall, pressure-dependent leakoff, which can be indicative of highly productive fractured reservoirs, is the most common leakoff type in all Rocky Mountain basins. The analysis also shows orders-of-magnitude variation in gas permeability within all basins, with observed gas permeability ranging from less than 0.001 to greater than 0.10 md.
Summary This article describes the use of associative polymer technology (APT) to achieve fluid diversion during an acid stimulation treatment. APT involves the use of a very-low-viscosity aqueous-polymer solution. It reacts immediately with the formation surface to significantly reduce the ability of subsequent aqueous fluids to flow into high-permeability portions of the rock. The first stage containing the APT predominately will enter the most permeable area, diverting the following acid stage(s) to less-permeable sections of the rock. APT has little or no effect on the flow of subsequent hydrocarbon production. Furthermore, in rock containing significant proportions of sandstone-type lithology, the water permeability of the treated zone is decreased permanently, resulting in post-treatment reduced water production from the treated zone. A general description of associating polymers and their properties, as well as a detailed description of the laboratory development of the current system, are both discussed. Laboratory data will show the effectiveness of APT in reducing the ability of aqueous fluids to flow through porous media. Parallel flow studies using water-saturated and oil-saturated cores are presented that show the ability of APT to divert acid in both sandstone and carbonate cores. These tests also show the ability of APT to decrease water permeability in the water-saturated core while the diverted acid increases the oil permeability of the oil-saturated core.
Summary Foam stability is an important parameter for foam fracturing. Bench-top testing is useful for screening but does not address the necessary conditions of temperature, pressure, pH [particularly with carbon dioxide (CO2) systems], and dynamic-flow conditions that can have unexpected influence on the foam's performance. A laboratory apparatus has been constructed for measuring the rheology of circulating-foam fluids to 400°F and 3,000 psi. The apparatus is equipped with a circulation pump, view cells, foam generator, mass flowmeter, and piping for loading a foam of the desired quality using either nitrogen (N2) or CO2. The foam rheometer is intended for evaluation of foam stability with time and comparison of various foam formulations for application in foam fracturing. The foam loop was designed to mimic shear rates found in a fracture or reservoir, which are typically 200 s−1 or less. The rheology is measured by monitoring the pressure drop across a 20-ft length of ¼-in. tubing maintained at temperature in an oven. Flow rate is continuously adjusted, to ensure a constant shear rate in the tubing, by the software using continuous mass-flowmeter input. Results relating to CO2 and N2 foams are discussed with emphasis on foam persistence, bubble size and population, and the rheological behavior with time. Temperature, pressure, and additives affect both foam texture and foam stability. The adoption of a standard technique patterned after this work for evaluating foam rheology could impact the use and development of foam fluids in the future.
Summary This paper describes the conceptual design of an offshore liquidified natural gas (LNG) import terminal based on the "Bishop Process," sited on Vermilion block 179, offshore Louisiana. The Bishop Process comprises direct regasification of LNG in the dense phase and storage of the gas thus produced in salt caverns. (For conversion factors of units commonly used with LNG, please refer to Table 1.) The operating principles of this process are discussed, as well as the design considerations for the regas, storage, and send-out facilities. The single-point mooring (SPM) system for the offloading of LNG carriers is described, as well as the verification process thereof. The foreseen marine operations at the terminal are explained, and the work done confirms the technical and economical feasibility of the concept.
Summary A probabilistic/mechanistic modeling was carried out to develop a predictive model for fully developed slug-length distribution in a horizontal pipeline. Statistical analysis suggested the appropriateness of a log-normal model over an inverse-Gaussian model for predicting slug-length distribution. A total of 64 data sets were used to empirically correlate the log-normal model. Two empirical relationships for mean slug length and slug-length standard deviation were developed. A statistical analysis revealed that, in addition to pipe diameter and mixture velocity, volumetric flow rate of the liquid film in the bubble region and the momentum exchange between the slug body and the liquid film are significantly correlated to the mean slug length. The slug-length standard deviation was found to have a significant correlation with film liquid holdup and momentum exchange. A model-validation study demonstrated the capability of the probabilistic/mechanistic model to reproduce the experimental data with a satisfactory match. The match was improved when the developed correlations were tuned using the statistical confidence intervals (CIs) of their coefficients.
Summary Undesired heat loss from the production tubing, or uncontrolled heat transfer to outer annuli, contributes to the formation of gas hydrates and causes the deposits of paraffin and asphaltene materials that reduce the production rate. The successful application of thermal-insulating fluids in the last several years has demonstrated that such fluids can control heat loss effectively. In some cases, heat loss from the produced fluids caused by conduction and convection can be reduced by more than 90% when compared with traditional packer fluids. Recently, a new thermal-insulating-fluid system with superior thermal properties has been developed. Compared with the existing insulation fluids, the new insulating-fluid system provides high viscosity at a low-shear-rate range to reduce the fluid-convection rate. It also provides lower viscosity at high-shear-rate range to facilitate fluid placement. The new fluid, with improved insulation properties, has proved to be an attractive alternative to the current insulation method for deepwater risers. This paper highlights the development of this new thermal-insulating fluid and its application in deepwater-riser insulation in the Gulf of Mexico (GOM). Laboratory data and field cases are also presented to demonstrate the effectiveness of this fluid system.
SummaryThe scale-control challenges for two North Sea carbonate reservoirs are reviewed in this paper. While carbonate reservoirs are not the largest source of hydrocarbons within the North Sea, they are very significant on a global basis.The mechanism of scale-inhibitor chemical retention observed for phosphonate, polymer, and vinyl sulfonate copolymer (VS-Co) inhibitors on carbonate-reservoir substrates is outlined. Chemical placement represents the most significant technical challenge when performing scale-inhibitor squeeze treatments into fractured chalk reservoirs. Examples from more than 50 field treatments applied in reservoirs E and V, in which both phosphonate and VS-Co chemicals have been deployed, are used to illustrate the difference in chemical retention observed in laboratory evaluations. The laboratory studies demonstrated clear potential for significant extension in treatment lifetime by changing from a phos-phonate to a VS-Co-based scale inhibitor. The selection and qualification of chemical-placement systems for deployment of inhibitors in fractured carbonate reservoirs are also outlined. To this end, novel technologies to enhance conventional scale-inhibitor-chemical placement are vital to economic success during waterflood projects.
Summary A new way of reservoir management is dawning on the horizon: intelligent-reservoir management using continuous data from intelligent wells and/or smart fields. Even though there are many different buzz words for this new technology, they all lead to the same thing—managing a reservoir in real time or close to real time. Real time usually means reacting to an event as it happens or within a short time lag. In the petroleum industry, however, real time is different. This short time lag can be hours, days, or even weeks, which highly depends, of course, on the objective of a project. Integrating real-time data into a reservoir-management workflow, and turning the data into value, is a complicated task. The bottleneck for the data flow, right now, is the transfer of the realtime data, measured with time increments by the second and/or minute and stored on a real-time server, to the engineers' desktops in a clean, timely, and useful fashion. This paper shows ways to provide a continuous (i.e., 24-hours-a-day/7-days-a-week) flow of clean data to the engineers' desktops as a first step in the intelligent-reservoir management. It shows that the implementation of a smart field rises or falls with its ability to provide the data to the information specialist—the petroleum engineer. Because the data are coming into the database very frequently (e.g., at times, every hour or every other day), the engineer is not able to check these data for discrepancies. Therefore, intelligent-reservoir management needs an alarm system that informs the engineers of any underperformance or critical condition of a well or a reservoir. Another important aspect to the intelligent-reservoir management system is the integration of the standard petroleum engineering tools [e.g., decline-curve analysis, material balance, inflow performance relationship (IPR) curves, and reservoir simulation] into this work process. Currently, an IPR curve not only gets data every other month but every other day. This gives the engineer completely new opportunities for closer observation of the workflow (e.g., monitoring the permeability impairment over time). Well tests are usually a snapshot in time, but with continuous surveillance of the reservoir parameters, the development of the skin, for example, can be followed over time and preventative actions can be taken (i.e., predictive maintenance). Neural networks and genetic algorithms are other powerful tools in the real-time environment for handling large amounts of data. A neural network learns from the data gathered and detects underlying relationships—the more data, the better the network can detect these relationships. Once the underlying relationships have been established, the neural networks can be used for predictions (predictive data mining) such as predicting sand production. This approach gives the engineer time to react and prevents the equipment from getting damaged. This work provides a straightforward way of integrating realtime data into a reservoir-management process, and its methodology implies how to gain value from the information provided by a continuous data stream.
Summary This paper presents the development of a correlation that corrects for error in single-phase horizontal-well productivity calculations made by neglecting frictional pressure drop in the wellbore. Frictional pressure drop within the wellbore is frequently a controlling factor on the performance of long horizontal wells. Frictional pressure drop could be especially significant in wells completed with screens and slotted liners. This pressure loss is neglected in traditional inflow-performance (IPR) calculations, such as those developed by S.D. Joshi and by D.K. Babu and A.S. Odeh. This study develops a correction that can be added to these analytical IPR relationships to account for friction. This correction is based on a dimensionless group that combines well and reservoir information. It is easy to evaluate and can be readily used in nodal analysis. The correction was developed on the basis of more than 5,000 finite-difference-simulation runs, using a simulator with the capability to model wellbore friction. These runs spanned a wide range of well and reservoir parameters. The results are presented in terms of productivity errors (PEs); that is, the flow rate without friction minus the flow rate when friction is included in the model, divided by the flow rate reported without friction. The study found PEs as high as 90% in some cases (usually long wells with a small wellbore radius). These errors could lead to poor decisions on field development and production facilities. This paper presents a simple way to improve well-productivity predictions without requiring a reservoir-simulation model to take account of frictional pressure drops in the wellbore.
SummaryThis paper illustrates the importance of internal-corrosion-management and -integrity strategy in the development of new offshore-production areas in shallow and ultradeep waters in Brazil, where there is no other production facility nearby. Starting production activities in these areas without any facility—especially pipelines—is a challenge because the investment necessary is high, particularly when the first area to be produced is a gas block. The financial feasibility of a small- or medium-sized gas field with very low condensate production is extremely delicate because this kind of project usually demands high initial investments, particularly with topside facilities, platform structures, and pipelines.The financial scenario worsens as the first investment must consider not only the area to be put into production, but also other potential areas nearby with exploration still under way. To foresee fluid composition and all flow-parameter scenarios is a complex but necessary exercise to reduce risk and keep the operating expenditure (OPEX) as low as possible.One of the aims of this paper is to show one experience in the design of offshore gas fields in the shallow waters of Espirito Santo, Brazil, where pipeline-corrosion management and integrity strongly affected the capital expenditure (CAPEX) and OPEX factors because the flow-rate capacity was overdesigned to transport future production from adjacent fields.This paper discusses some of the newer issues related to the CO2-corrosion-risk-assessment and -integrity strategies. The paper also briefly discusses some current key issues regarding the ultradeepwater fields related to areas of uncertainties caused by internal corrosion, such as pipelines operating under supercritical flow and steel catenary risers operating within a corrosion-fatigue environment.
Summary The Otter field is the first "dual" electric submersible pump (ESP) completion in the U.K. sector of the North Sea in a subsea field development. This subsea development consists of three horizontal openhole oil producers and two cased-hole water injectors clustered around a production manifold and tieback, 21 km from the Eider host platform. Each oil producer has been able to deliver up to 20,000 BOPD since October 2002. Because a risk of sand production was identified during the life of the field, downhole sand control was deemed necessary. Well longevity has a major impact on the global-project economics. This meant that achieving and maintaining sand-free production through optimal completion design was critical to the overall success of the development. This paper describes the strategy adopted and the factors considered in the development of the sandface completion design for the field's life. The sand-control technique had to be decided upon while drilling the well, on the basis of the drill cuttings-particle-size analysis—oversmall particles would have lead to an openhole gravel pack. It appeared that correct geosteering was permitted to stay within a sand body that was adequate for standalone screen completion, which the authors consider the best option (i.e., in cost, risk, and efficiency) when applicable. The operational experience gained and lessons learned on the first well contributed to the design enhancements required for completion of the horizontal wells described in this paper.
A new technique for characterizing secondary and tertiary reactions during sandstone-matrix-stimulation treatments is presented. In the new technique, traditional experiments on short reservoir cores are supplemented with measurement of the effluent-element concentrations, batch-reactor experiments, and geochemical simulations to predict the extent of secondary and tertiary reactions in the reservoir treatment. Alternative methods of characterizing secondary and tertiary reactions, such as those using long core flow tests and laboratory radial-flow setups, are reviewed.The new design technique is used in designing a treatment for a well in the North Sea. Details of how this technique was applied to the treatment design are presented. Post-treatment data from the well showed a successful matrix-treatment design. The production from the well increased by 1,400% immediately after the treatment. The 3-month stabilized production gain was 650%.
Summary To date, most of the research concerning the separation process has had a deterministic approach because of its orientation to steady-state-flow regimes. However, this assumption is far from true when many artificial intermittent gas lifted (IGL) wells are connected to the same separator. IGL wells have flow/no-flow periodic conditions associated with long accumulation stages and short production stages lasting approximately 20 minutes and 1 minute, respectively. A stochastic algorithm was developed to simulate the separation process and the proper periodicity of each IGL well, along with the unpredictable delay or synchronization between those wells. The simulation couples the dynamic mass-balance equations in the separator and the Monte Carlo method for predicting the gas and liquid rates associated with the superposition of the IGL wells. The input parameters for this simulation include daily gas/oil production and cycle time of each well, the oil properties, separator pressure and temperature, and the control scheme. The simulator output matched with less than 10% of the field data. The results obtained with the approach suggested in this work could be used for new criteria in design, simulation, and evaluation of separation facilities under fluctuating conditions.
SummaryDrill-in fluids contain biopolymers such as xanthan gum, cellulose, and/or starch, along with bridging agents like sized calcium carbonate particles. These polymers are used to enhance the carrying capacity of the mud and to form a filter cake to minimize leakoff of the drilling fluids into the formation.Proper removal of drilling-mud filter cake is essential to minimize formation damage. The damage becomes more intense in tight formations, especially in horizontal gas wells in which the drawdown is not high enough to dislodge the filter cake. Another source of damage is the mud filtrate where fines migration and water blockage can occur in tight formations, especially in sandstone reservoirs.A thorough laboratory investigation of formation damage induced by drill-in fluids (water-based) was conducted. A mini-flow loop was used to assess formation damage induced by polymers present in the drill-in fluid. Various cleaning fluids were examined and their effectiveness in removing the filter cake was determined. These fluids included acidic brines, surfactants, mutual solvents, specific enzymes, and combinations of these fluids. The retained permeability of reservoir cores was determined for each cleaning system. This paper presents results obtained from the laboratory and recommendations made to remove drilling-mud filter cake from horizontal gas wells in a deep sandstone-gas reservoir.
Summary A laboratory study characterized partially formed chromium(III)-carboxylate/acrylamide-polymer (CC/AP) gels for water shutoff in fractures. These partially formed gels showed much lower effective viscosities during placement than comparable fully formed gels. During placement, leakoff rates through fracture faces were low for gelants and partially formed gels. During the first brine injection after gel placement, the pressure gradient required to breach the gel increased with the increasing polymer concentration. Most gel remained in the fracture and did not wash out. During brine flow through "wormholes" in the gel, stabilized residual-resistance factors (Frr) were large and increased with increasing polymer concentration.
SummarySeveral horizontal wells have been drilled in different sandstone formations in Sumatra. These formations have a typical permeability of 100 to 500 md, a low bottomhole pressure (BHP) of 450 to 750 psi, and a bottomhole temperature (BHT) of approximately 200°F. The wells are completed with a perforated liner. The objective of the horizontal-drilling program was to increase oil recovery in low-permeability estuarine reservoirs. Some of the drilled horizontal wells did not perform to expectations, and an intensive study was undertaken to identify completion and stimulation opportunities to increase production.During this study, all aspects of the initial completions were examined and redesigned.The drill-in mud was reformulated to reduce the amount of polymer and increase the use of fine calcium carbonate to decrease lost circulation during drilling and to simplify the removal of filter cake during initial completion.Core tests were performed to identify the optimum fluid formulation, which dissolves the remaining filter cake but does not destroy the formation's natural permeability.A new way of removing the filter cake after completing the well was introduced using oxidizer technology.A new, true-fluidic oscillator (TFO) was used to remove near-wellbore skin (in conjunction with an improved acid system) for wells that have been producing for several months or years.The paper presents several case histories to discuss how completion and stimulation problems were systematically evaluated resulting in increased horizontal-well production.
Summary The natural state of asphaltenes in petroleum fluids is described as a colloidal system stabilized, to some extent, by the resins that act as peptizing agents. Destabilization of colloidal asphaltenes appears to happen as a result of changes in temperature, pressure, and composition. This can significantly affect the production efficiency of a reservoir during oil recovery. The phenomenon of asphaltene flocculation and deposition in well tubing appears to be influenced by two mechanisms: the fluid-phase (gas/liquid/solid) separation and the well-flow regime. Predictions of the onset of asphaltene flocculation determined by fluid-phase laboratory studies do not necessarily imply that asphaltene deposition will occur during flow conditions. This paper presents a method for predicting the onset of asphaltene deposition under well-flow conditions. This method will allow us to take preventive actions before asphaltenes problems occur by keeping the asphaltenes dispersed in the oil phase. A well-monitoring technique was used in west Kuwait Marrat (Jurassic) deep wells to monitor the well-flow pressure by use of a programmable data logger. The data gathered from the logger predicted the onset of the flow-regime mechanism that influenced asphaltene deposition in well tubing. The deposition thickness of asphaltenes in well tubing was estimated by the data and was found to agree with the results obtained by the caliper test.
Summary An improvement has been made in anticorrosion chemicals for oilfield use. A binary corrosion inhibitor that combines an epoxy resin and an amine curing agent has been patented and field proven. The proper application of this unique combination of chemicals forms a bond with the oxide film present on downhole metal surfaces. The result is a corrosion-inhibitor barrier that is more tenacious than conventional polar-filming amines, reducing application frequency and labor costs and, even more important, downhole failures. The binary corrosion inhibitor is also an improvement over, and is more versatile than, other epoxy-amine products.
Summary This paper discusses experimental work associated with the evaluation of asphaltene precipitation for a field in Abu Dhabi, UAE. This reservoir is in the early stages of development and will be put on production using a combination of gas-, water-, and water-alternating-gas- (WAG) injection schemes in early 2006. The field has not shown operational problems resulting from asphaltene precipitation during primary production. Laboratory experiments using the transmittance of an optimized laser light in the near-infrared (NIR) wavelength (≈1600 nm) were used to first confirm the stability of asphaltene in the reservoir fluid. Two cases covering the expected extremes in terms of the field gas/oil ratio (GOR) were evaluated. Isothermal depressurization tests were also conducted at reservoir, wellhead, and separator temperatures (250, 190, and 130°C, respectively). Several additional light-transmittance experiments were conducted to evaluate the asphaltene-instability regions resulting from reservoir-fluid contact with various concentrations of rich gas and carbon dioxide (CO2). Measurements using high-pressure filtration were also collected to quantify the bulk precipitation of asphaltene with various molar concentrations of gas. Finally, tests were conducted using state-of-the-art technologies to evaluate the consistency of the initial NIR runs. These technologies involved the use of a spectral-analysis system (SAS) to evaluate asphaltene-particle size and growth rate and high-pressure microscopy (HPM) images to visually confirm the measurements. Results indicated that rich hydrocarbon gas in contact with reservoir fluid destabilizes asphaltene. The amount of the bulk precipitation increased with higher concentrations of rich gas in the reservoir fluid. Particle sizes were estimated to be in the range of 0.5 to 1 µm. The effect of CO2 was found to be less severe with regard to asphaltene instability.
