The field development phase prior to investment sanction is characterized by relatively large uncertainties at the time important decisions have to be made. It is, for instance, crucial to select an appropriate recovery strategy (depletion or injection) to obtain optimal hydrocarbon cumulative production whilst ensuring good profitability of the project. Evaluation of reservoir as well as economic uncertainties and quantification of their impact are needed before the field development concept selection.
This paper describes how to stochastically assess reservoir and economic uncertainties and the screening process used to select the best recovery strategy. The chosen methodology is the combination of uncertainty studies, including both continuous, discrete and controllable parameters. The different screened scenarios are combined in a stochastic decision tree, built-up through decision and chance nodes, to establish a distribution of recoverable volumes and rank the recovery strategies given a chosen criterion. A second uncertainty study is performed by adding economic uncertainties to the initial set of reservoir uncertain parameters. Eventually a new decision tree is established and scenarios ranked using economic criteria.
The application of this methodology to an oil field from the Norwegian continental shelf and how recovery strategies are ranked are presented in this paper. The described methodology has exhibited the risks and uncertainties carried by the project, as it was possible to rank the different solutions based on the dispersion of the recoverable volumes distribution and/or on the net present value (NPV). In the context of a marginal or large capex project, a robust P90 case is required and this may therefore influence the choice of the recovery strategy. For instance, a scenario yielding the largest hydrocarbon volume may not be selected because it requires too many wells and/or too large investment if one of these criteria is defined as the most important. In addition, the combination of uncertainty studies enabled a full economic evaluation covering the entire recoverable volumes distribution whereas in many projects economic evaluation is focused on the P90, Mean and P10 scenarios.
The two-step integrated approach allows a decision to be made whilst taking into account both reservoir and economic aspects. Having a combined stochastic approach to the reservoir and economic uncertainties avoids a biased decision. All cases are stochastically covered and screened using a systematic and unified methodology that gives the same weight to each scenario.
The PDF file of this paper is in Russian.
Multistage fracturing (MSF) technology becomes one of the main stimulation methods in horizontal wells. Despite the considerable experience, accumulated engineering knowledge and market appearance of a sufficient number of various MSF equipment manufacturers, operators are still rising the following questions while performing this type of well interventions: horizontal well length justification, number of MSF zones, distance between the ports, placement of open hole packers, recovering of frac balls etc. All of the above can be resolved to some extent with the help of traditional geophysics. However, production logging tool (PLT) performance in horizontal wells with MSF in most cases is limited by many complicating technological factors that reduce the possibility of successful surveillance. Most of the questions related to the surveillance of horizontal wells with MSF can be resolved using the technology of chemical markers integrated into a wide range of completion designs. This technology involves the installation of special polymer matrices with embedded intelligent chemical markers, either oil sensitive or water sensitive, into the completion hardware within the each zone of the MSF. When contacted by the target fluid (water or oil), the unique chemical signatures are released in very small concentrations and production from each reservoir compartment transports these unique signatures to the surface. Collection of the produced fluid samples at surface, analysis and interpretation, allows to resolve a wide range of conventional PLT tasks without conducting the PLT, including: the assessment of well clean-up, frac balls efficiency or sliding sleeves performance, quantification of the inflow per each zone monitored, detection of water breakthrough intervals and selection of zones for re-fracturing. This article presents practical case studies of intelligent inflow indicators applications for monitoring the MSF wells.
Технология многостадийного гидроразрыва (МГРП) пласта становится одним из основных методов интенсификации притока в горизонтальных скважинах. Несмотря на значительный опыт, накопленные инженерные знания и появление на рынке достаточного числа производителей оборудования для МГРП, при планировании и проведении МГРП в горизонтальных скважинах возникает необходимость решения следующих вопросов: обоснование длины горизонтальной скважины; выбор числа зон МГРП, расстояния между портами и расстановки заколонных пакеров; проверка выхода шаров в случае использования шаровой технологии и др. Указанные задачи в определенной степени могут быть решены с помощью традиционных промыслово-геофизических исследований (ПГИ). Однако проведение ПГИ в горизонтальных скважинах с МГРП в большинстве случаев ограничено рядом осложняющих технологических факторов, которые снижают охват скважин исследованиями. Большинство вопросов, связанных с исследованиями горизонтальных скважин с МГРП, может быть решено с помощью технологии стационарных интеллектуальных химических маркеров, установленных на элементах заканчивания. Данная технология предполагает установку специальных полимерных матриц, содержащих химические маркеры для воды и нефти, в каждой зоне МГРП на оборудовании заканчивания. При контакте с целевым флюидом (водой или нефтью) полимерные матрицы начинают выделять данные химические маркеры, которые выносятся вместе с потоком пластового флюида. Отбирая пробы на поверхности и проводя последующий анализ, можно решить широкий круг задач ПГИ без его проведения, в том числе оценить качество освоения скважины, проверить выход шаров или срабатывание сдвижных муфт, количественно оценить интервалы притока, определить интервалы прорыва воды и выбрать зоны для повторного гидроразрыва. В статье представлены практические примеры использования технологии интеллектуальных индикаторов притока для мониторинга скважин с МГРП.
The initial development of inflow tracers was initially designed to provide qualitative information about identifying the location of water breakthrough in production wells. The proof of concept and application for water detection, initiated the development of oil tracers for oil inflow monitoring. Different approaches to install them permanently within a completion component were used, to provide risk free, reliable production monitoring without the need for intervention. Installing unique chemical tracers that are embedded in polymer materials in sand screens or pup joints, along select locations in the lower completion was to correlate where the oil and water is flowing along the production interval and how much. Innovation in the chemistry and materials designed to release to a target fluid (oil or water), enabled non electric wireless monitoring capabilities for many years of longevity in harsh well conditions, such as high temperature and highly acidic stimulation fluids. The evolution of inflow tracer signal interpretation, qualitative and quantitative interpretation workflows using models have also provided valuable insight to inflow characterisation. The latter can provide zonal rate information like wireline conveyed production logging tools, by inducing transients through shut in's or rate changes to create tracer signals that are transported by flow to surface and captured in sample bottles for laboratory analysis. A model based approach to match the measured signals with proprietary models through history matching workflow has also been developed. There are hundreds of well installations utilising inflow tracing monitoring technology today, where the majority have been in open hole completions in both sandstone and naturally fractured carbonate reservoirs on land, offshore environments in both platform and deep water sub-sea environments producing through long tie backs to FPSO's. The monitoring sensors are adaptable to most completion types in conventional and unconventional reservoirs. In most cases, inflow tracers can monitor clean-up efficiency, any subsequent restart and steady state production. Practical case studies will discuss the development of robust and reliable inflow tracer and technology and how operators have applied it over the past decade in a chronological order.
This paper describes the analysis, test and design work to deliver an optimum lower completion for a tri-lateral well, by integrating autonomous and passive inflow control devices (ICD), in the Alvheim field offshore Norway. Chemical tracers, permanently installed in the completion, enabled the evaluation of inflow performance in each lateral. This continues to give valuable information to assess whether the tri-lateral completion is performing as predicted, improves reservoir characterisation and guides reservoir management decisions.
In 2015, both passive and autonomous inflow control devices (AICD) were tested in the laboratory with Alvheim fluids at reservoir conditions. The experimental flow testing, reported in this paper, demonstrated that the AICD chokes gas more efficiently than the passive ICD, but also that the strength of the AICD were lower than expected a priori. The experimental results were used to model the AICD correctly and establish a lower completion strategy as follows: where the well was close to the overlying gas cap, AICDs should be used, while passive ICDs with variable strength were to be used elsewhere to optimise the inflow.
Steady-state inflow modelling was performed before the drilling operation and updated accordingly with the as drilled information. The lower completion design for each branch focused to get what was estimated to be an optimal inflow based on oil volume in place. A key uncertainty in the design work was whether shaly zones along the wellbore would creep/collapse with time and act effectively as packers or not. The lower completion covered around 7 km of reservoir penetration in the three branches, and 15 unique oil tracers were installed to evaluate the clean-up and the inflow profile along the well. The well started producing in May 2016 and downhole flow control valves enabled a successful clean-up, as confirmed by oil tracer responses. In addition, a restart tracer sampling campaign was done after a 12-day shut-in, in August 2016, and this formed the basis for a "chemical production log". The tracer based inflow interpretation is compared quantitatively with the model predicted inflow and qualitatively to the tracer responses seen during the clean-up. This gives valuable feedback to the completion design, and assist in understanding the various degrees of pressure support and if the shaly reservoir sections have creeped/collapsed or not.
The well has exceeded pre-drill production expectations, with an average oil rate of 3375 Sm3/d (21240 stb/d) during the first production year. This is a consequence of higher than expected NTG, but is also partly a result of the lower completion design, where the focus has been to optimize the lower completion such that the whole well contributes, from the heel to all toes. To the knowledge of the authors, this is the first well in the world with a lower completion integrated with AICDs, ICDs and chemical tracers.
Understanding the actual inflow distribution across the reservoir interval is valuable for optimizing reservoir management decisions. It is common to have varying levels of uncertainty in the petrophysical prediction of the inflow distribution. The inflow distribution assessment drives many aspects of the field development plan. A technique is presented for acquiring quantitative measurements of the inflow rate of various reservoirs or layers of a reservoir at various times in the life of the well using interventionless technology.
Chemical tracers are embedded in sand screens that are positioned adjacent to reservoir layers at different depths of a well such that fluid exposure causes release of a unique chemical compounds into the oil produced from each layer. Analysis of the transient behavior of each of the chemical compounds from samples of the produced oil provides a quantitative assessment of the rate of inflow occurring from the adjacent reservoir section. The chemical tracer based measurements of inflow are compared to the petrophysical predictions of inflow distribution. The petrophysical rock and fluid properties are determined using tools such as LWD and core analysis. It is common for these sources to contain uncertainty in their assessments of the inflow potential. The chemical tracer technique provides an assessment of the actual inflow distribution that can be compared to the petrophysical prediction. This additional input is very valuable in reducing the uncertainty in the overall reservoir performance assessment.
Case histories from two wells in frac-packed wells are presented. Both wells had substantial uncertainties in the petrophysical assessments of the inflow performance of layers in the reservoir. The results from the chemical tracer technique provided insight that led to high value decisions. In Case History #1, the chemical tracer showed a layer to be contributing non-commercial rates. The petrophysical based prediction of inflow indicated this zone was of lower quality than the other zones but it was decided to complete the zone as there was possibility of producing economic rates. Significant savings will be realized in future wells by not completing the non-commercial layer. In Case History #2, the overall productivity of the well was substantially below predictions of the petrophysical data. The chemical tracer inflow profile showed all zones producing similarly. The assessment of similar inflow in each layer implied the kh prediction from LWD to be overly optimistic. This insight changed the production profile forecast for future wells. This insight also prevented the need to perform an expensive PLT log in the well to determine if the entire interval was flowing.
Measuring the actual inflow distribution across the reservoir interval in deep, frac packed wells is usually so impractical or prohibitively expensive that it is never performed. The technique presented of using chemical tracers embedded in the completion components provides an on-demand, low cost and minimal risk means of assessing the actual inflow distribution. The inflow distribution information is combined with other data sources to reduce the uncertainty of reservoir management decisions.