Wellbore instability is caused by the radical change in the mechanical strength as well as chemical and physical alterations when exposed to drilling fluids. A set of unexpected events associated with wellbore instability in shales account for more than 10% of drilling cost, which is estimated to one billion dollars per annum. Understanding shale-drilling fluid interaction plays a key role in minimizing drilling problems in unconventional resources. The need for efficient inhibitive drilling fluid system for drilling operations in unconventional resources is growing. This study analyzes different drilling fluid systems and their compatibility in unconventional drilling to improve wellbore stability.
A set of inhibitive drilling muds including cesium formate, potassium formate, and diesel-based mud were tested on shale samples with drilling concerns due to high-clay content. An innovative high-pressure high temperature (HPHT) drilling simulator set-up was used to test the mud systems. The results from the test provides reliable data that will be used to capture more effective drilling fluid systems for treating reactive shales and optimizing unconventional drilling.
This paper describes the use of an innovative drilling simulator for testing inhibitive mud systems for reactive shale. The effectiveness of inhibitive muds in high-clay shale was investigated. Their impact on a combination of problems, such high torque and drag, high friction factor, and lubricity was also assessed. Finally, the paper evaluates the sealing ability of some designed lost circulation material (LCM) muds in a high pressure high temperature environment.
Gupta, M K (Oil and Natural Gas Corporation Ltd) | Sukanandan, J N (Oil and Natural Gas Corporation Ltd) | Singh, V K (Oil and Natural Gas Corporation Ltd) | Pawar, A S (Oil and Natural Gas Corporation Ltd) | Deuri, BUDHIN (Oil and Natural Gas Corporation Ltd)
In an offshore field, mitigation of H2S from natural gas itself is a big challenge. A situation where high H2S present in well fluid increases the challenges several fold to sweet both processed oil and gas. In a wellhead platform/remote location where manual intervention requirement is minimal, conventional process has several limitation such as space availability, load on structure, frequent monitoring etc., hence may not be suitable for mitigation of H2S from processed gas and oil.
In this work, an approach is adopted for sweetening of sour gas and sour crude in an optimum way, keeping offshore constraints in mind and without usage of rotating equipment's. An integrated simulation model is developed in Aspen HYSYS process simulator wherein well fluid from well manifold is processed in three phase oil and gas separator. The gas liberated from the separator is first sweetened in adsorption columns considering three bed systems unlike general usage of two. The oil is sweetened in an envisaged stripper column utilizing sweet gas from adsorption column as stripping gas. In this work, a three bed adsorption column is envisaged wherein 1st two column in used for sweetening of gas liberated from separator which consists of around 7500ppm H2S. Sour oil from the separator which contains around 2000 ppm of dissolved H2S is processed in a stripper column for mitigation of H2S dissolved in the oil. Sweet gas liberated from 1st two column of adsorber bed is used as stripping gas for oil sweetening. H2S liberated from stripper column is routed to the 3rd column for sweetening. After this gas from all the adsorber column is combined and routed to process platform along with the sweet oil. Analysis reveals that, this scheme can sweeten altogether both oil and gas to the desired H2S level without the need of any rotating equipment's and must be a suitable for remote location.
A holistic approach was taken for sweetening of oil and gas without the need of any rotating equipment's, & any chemicals, unlike the conventional method and hence can be suitably adopted for an offshore environment or at remote location where requirement of manual intervention is bare minimum.
Identification of a prospect is normally done based on seismic interpretation and geological understanding of the area. However, due to the inherent uncertainties of the data we still observe in many cases that all key petroleum system elements are present, but still the drilled prospect is dry. Such failures are mostly attributed to a lack of understanding of seal capacity, reservoir heterogeneity, source rock presence and maturation, hydrocarbon migration, and relative timing of these processes. The workflow described in this paper aims to improve discovery success rates by deploying a more rigorous and structured approach. It is guided by the play-based exploration risk assessment process. The starting point is always that the process is guided by the the basic understanding of a mature kitchen should always be based on a regional scale petroleum systems model. However, while evaluating prospects, the migration and entrapment component of a prospect should always be investigated by means of a locally refined grid-based petroleum system model. The uniquepart of this approach is the construction of a high-resolution static model covering the prospects, which is built by using available well data, seismo-geological trends and attributes to capture reservoir potential. Additional inputs such as fault seal analysis also helps to understand prospect scale migration and associated geological risks. In the regional play and local prospect-scale petroleum system models, geological and geophysical inputs are utilized to create the uncertainty distribution for each input parameter which is required for assessing the success case volume of identified prospects. The evaluated risk is combined with the volumetric uncertainty in a probabilistic way to derive the risked volumetrics. It is further translated into an economic evaluation of the prospect by integrating inputs like estimated production profiles, appropriate fiscal models, HC price decks, etc. This enables the economic viability of the prospects to be assessed, resulting in a portfolio with proper ranking to build a decision-tree leading to execution and operations in ensuing drilling campaigns.
PY-1 is one of the few fields in India producing hydrocarbons from Fractured Basement Reservoir. The field was developed with nine slot unmanned platform with gas exported through a 56 km 4" multiphase pipeline to landfall point at Pillaperumalnallur. Field was put on production in November 2009 with three extended reach wells. The production performance of the field had some surprise and declined earlier than expected. As a result, based on the conclusions drawn from an integrated subsurface study, a two wells reentry campaign to side track wells Mercury and Earth was planned to be executed in Q1 2018. The objectives of this paper are twofold: 1. Review the production performance of a granitic basement gas field and share learnings which may be useful for similar fields being developed elsewhere.
The negative impacts of high water cut in mature fields are well known within the oil & gas industry. Water production preventive & mitigative measures are well established and documented: Wireline or coil tubing conveyed diagnostic and work-over operation(s) is one of such common preventive measures. This paper, through a series of integrated case studies will highlight the best practices for wireline conveyed logging and work-overs with one common goal, i.e. to achieve the water production to a minimum acceptable level in deviated high water cut wells.
The prolific XYZ field is located in the Northern North Sea and it produces oil from Jurassic Brent Group. Oil production from the XYZ reservoir started in early 1978, with 43 producing wells and 15 water injection wells targeting the Rannoch, Etive, Ness and Tarbert sands. Oil and gas production peaked in 1982 and since then production has steadily declined for this field. The increasing water cut in the wells of this field is presenting a challenge for the operating companies.
Production profiling using advanced Production Logging data, casing/tubing integrity check using Multi-Finger Caliper data and saturation monitoring using cased-hole Reservoir Saturation data was done in these wells to ascertain the water producing zones and do the subsequent well intervention, if required. A strategic diagnostic test was designed to precisely evaluate the flow profile using advance production logging tool consisting of 5 mini-spinners & 6 sets of each electrical and optical probes; Real-time data assessment and analysis was done for different flowing rate surveys to validate the findings. Additionally, casing condition was evaluated using Multi-Finger Caliper to decide Plug or Straddle setting depths. Also, new hydrocarbon bearing zones were identified based on cased-hole saturation tool results. The analysis results boosted the cumulative oil production.
This study demonstrates the importance of making real time interpretation decisions at the wellsite and the benefit of developing a good working relationship between wellsite engineers and onshore technical support. The results of this work led to the unequivocal determination of major oil and water producing zones in deviated high water cut (95%+) wellbores which further helped in taking workover decisions to carry out water shut off, utilizing either plug or straddle technology. The findings of caliper data determined the appropriate plug or straddle setting depths. The results were compared and confirmed with the nearby well dynamic pressures and production data.
The technical approach and processes applied to wells of XYZ field is a valuable example guide to decide water shut off zones and technique of similar plays. This study consists of three integrated case studies from a mature field where water shut-off zones and technologies were decided based on the findings of production logging and well integrity data. Also, re-perforation jobs were performed based on the cased-hole reservoir saturation data results. These strategic workover operations ultimately led to significant increase in hydrocarbon production.
A novel method of measuring steady-state relative permeability, called the intercept method (IM), was recently introduced. The IM entails a modification of a standard steady-state procedure that incorporates multiple total flow rates at each fractional flow rate. The objective of the method is to measure data at each fractional flow rate that will permit simple analytical calculations to correct differential pressure (hence relative permeability) and saturation data for the effects of capillary pressure. The IM is intended to provide a corrective technique without the need for additional supportive analyses, such as capillary pressure and in-situ saturation monitoring (ISSM), or as an alternative approach to the current considered best practice of numerical coreflood simulation, which generally requires the specified additional data.
Consequently, the IM is of interest to the global industry in regions and/or laboratories that do not possess state-of-the-art equipment, or for its cost-saving potential. However, before employing this new method, it was important to the authors to investigate its validity across a wider range of rock properties, sample dimensions and wetting states experienced in commercial special core analysis laboratory (SCAL) coreflood experiments. This study thus draws on a variety of relative permeability curves (and supporting data) from various global core studies, originally derived by typical relative permeability methods plus coreflood simulation. From these data, we use SCORES (an open-source coreflood simulation software) to simulate the expected results of multiflow-rate steady-state experiments and use the IM to derive and compare the corrected relative permeability curves. Results highlight criteria under which the method does not provide fully corrected data. The paper explores these criteria in more detail.
There has been much work done on the optimal well placement and control including some investigates on optimizing well types (injector or producer) and/or drilling order. However, to the best of our knowledge, there are no journal articles on the following problem that is sometimes given to reservoir engineering groups: given a potential set of reasonable drilling paths and a drilling budget that is sufficient to drill only a few wells, find the optimum well paths, determine whether a well should be an injector or a producer and the drilling order that optimizes production. In this work, optimizing production means maximizing the net present value (NPV) of production over the life of the reservoir.
Here, this field development optimization problem is solved using the generally acknowledged Genetic Algorithm (GA). Mixed encodings are used to form the chromosomes. A binary encoding for the optimization variables pertaining to well location indices and well types is proposed to effectively handle the large amount of categorical variables while the drilling sequence is parameterized with ordinal numbers. The same selection procedure is used for the binary encoded parameters and the ordinal encoded parameters, however, different mutation and crossover operations are applied. These two sets of variables are optimized both simultaneous and sequentially. In sequential optimization, the first optimization assumes all wells are drilled at time zero and determines the optimal well locations and types, while the second optimization assumes there is only one drilling rig working on site and optimizes the drilling order based on the optimal solutions obtained in the first optimization. Finally, control optimization can be carried out to further improve the NPV of life-cycle production. The impact of well locations and types, drilling order and control settings on the NPV obtained with simultaneous and sequential optimization are compared.
We test the overall GA workflow on two basic examples, a three-dimensional channelized reservoir where the potential well paths are either vertical or horizontal and the Brugge model where only vertical wells are drilled. As GA is a stochastic algorithm, multiple runs for each problem are done in order to evaluate the average performance and robustness of the algorithm. Results indicate that GA gives good solutions in the following sense: (i) the NPV produced is significantly larger than the NPV of any member of a set of initial guesses; (ii) different runs of GA produce a variety of choices of optimal well paths, but the variation in the estimated optimal NPVs is relatively small; (iii) for problems where wells are under rate controls, GA consistently produces NPVs that are higher than the one obtained with the original gradient-based algorithm developed several years ago, albeit at a higher computational cost.
To the best of our knowledge, this paper presents the first work that focuses on the problem of choosing a set of optimal drilling paths and determining which well should be injector and which well should be producer given a large fixed set of possible drilling paths.
Al Kalbani, M. M. (Heriot-Watt University) | Jordan, M. M. (Nalco Champion) | Mackay, E. J. (Heriot-Watt University) | Sorbie, K. S. (Heriot-Watt University) | Nghiem, L. (Computer Modelling Group Ltd.)
Barium Sulphate (BaSO4) scale is a serious problem that is encountered during oilfield production and has been studied mainly for fields undergoing water flooding. Chemical Enhanced Oil Recovery (cEOR) processes involve interactions between the injected brine and the formation brine, rock and oil. Very little work has appeared in the literature on how cEOR processes can influence the severity of the mineral scaling problem that occurs in the field and how this can be managed. This study investigates barium and sulphate co-production behaviour, the deposition of BaSO4 in the formation and in the producer wellbore, and its inhibition during polymer (P), surfactant (S) and surfactant-polymer (SP) flooding cEOR processes.
Reservoir simulation has been used in this study, employing homogenous and heterogeneous 2D areal and vertical models. Data from the literature are used to define the parameters controlling the physical and chemical functionality of surfactant and polymer (e.g. oil-water interfacial tension, IFT, polymer viscosity and surfactant and polymer adsorption). Assessment is made of the minimum inhibitor concentration (MIC) required to control scale that is predicted to occur due to changes in brine composition induced by the water and chemical flooding processes. The expected retention and release of a phosphonate scale inhibitor during squeeze treatments in the production wells is modelled.
The high viscosity and more stable polymer slug reduces the mixing between the injected and the formation brines, reducing BaSO4 scale precipitation in the formation and delaying the potential scale risk in the producer wellbore compared to normal water flooding. Polymer adsorption causes retardation of the polymer front compared to the sulphate front, accelerating the scale risk in the wellbore. Polymer with low salinity make-up brine and low sulphate concentration not only improves polymer viscosity and enhances recovery, it also delays and reduces the scale risk in the formation and the producer. During surfactant flooding, from an oil recovery perspective, the optimal phase type and salinity can be any of the three microemulsion phase types, depending on the system multiphase parameters. However, the scaling risk can be different to that in the water flooding case, depending on the IFT, ME phase type, the injected salinity and sulphate concentration. In SP flooding, low salinity make-up brine is preferred to enhance oil recovery, and it also delays and reduces scale risk. The impact of the changing brine composition due to ion reactions affected the required MIC values over time. The impact of the MIC and salinity changes on inhibitor retention and release then influences the treatment volumes required to control scale over field life.
The study shows that barium and sulphate co-production and the evolving scale risk depend on the mobility ratio (which is determined by the injected brine and oil viscosities), on the oil-water IFT and on the level of chemical adsorption. The severity of the scale risk is also impacted by the flood techniques utilised, with the extent of reservoir reactions have an effect on the MIC required to control scale and the squeeze treatment volumes required to maintain production after breakthrough.
On the Vega gas condensate and oil field in the Norwegian North Sea, two high temperature, high pressure (HTHP) gas condensate wells on one subsea template in 370 m water depth were acid and scale inhibitor treated in order to improve productivity by acid scale removal and prevent future scaling. Significant amount of work was undertaken on design and qualification of the treatment fluids. In order to reduce operation time and increase efficiency, a novel one-time connection concept was utilized. During the operations, wells were kicked off after energizing with gas bullheaded from the neighbouring well. The treatment fluids were designed to reduce consequences for the host facility due to H2S generated during the operation - this required optimization after understanding of the H2S source as witnessed in prior treatments.
The new concept with one-time connection was successfully employed and allowed for three subsequent well treatments in a row, thus saving at least two days vessel operations time. The gas injection from the neighbouring well - the one not treated at the moment - allowed for an efficient start-up of the treated well without need for larger nitrogen injection which would have led to contamination and potentially to flaring due to off-spec gas. The introduction of a batch with pH neutralizer and H2S scavenger batch into the treatment design to be placed into the production pipeline reduced H2S liberation and production to the host facilities, thus limiting the operational stress on the platform. Productivity of well A1 showed an immediately significant increase after the operations, whereas productivity of well A2 required a longer clean-up than originally anticipated.
Khan, Muhammad Hanif (Independent) | Maqsood, Tahir (Tullow Pakistan) | Jaswal, Tariq Majeed (Pakistan Oilfield Ltd) | Mujahid, Muhammad (Spec energy DMCC) | Malik, M. Suleman (Qatar Petroleum) | Jadoon, Ehtisham Faisal (UEP Pakistan) | Hakeem, Uray Lukman (Qatar Petroleum)
This article investigates the seismic reflection geometries (possible reservoir) of Paleogene of Offshore Indus Basin Pakistan (shelf area) from 2D seismic and make an analogue with the proven carbonate reservoir geometries found in countries such as Canada and Middle East. The 2D seismic data are used to interpret the possible carbonate features and methods to identify them and define its depositional setting on the carbonate platform. The offshore Indus Basin is tectonically a rift and a passive continental margin basin, located in Offshore Pakistan and Northwest India where carbonates were deposited on the shelf and the deep offshore area during early post-rift phase. In the deep offshore area, carbonates were set on volcanic seamounts during the Paleogene age. In Paleogene, the Indian Plate was passing through the equator in the conditions of warmer water with appropriate water salinity, where those conditions were suitable for the growth of organisms responsible to develop reefs in the Offshore Indus area. The available seismic data analysis has indicated the possible presence of different carbonate reefs on the shelf. The seismic data enabled to define the possible carbonate Rimmed shelf depositional model in the area. The aim of this article is to highlight and analogue carbonate seismic geometries, their internal architecture in the Paleogene interval of the Offshore Indus Basin (shelf area) and how to identify them, which may help for further exploration in Offshore Indus Basin.