This paper presents a multidomain integrated workflow that combines geophysics, borehole geology, fracture modeling, and petroleum systems analysis for characterization and resource assessment of basement plays. A 3D fracture model is developed by integrating image log interpretation and seismic data to assess the reservoir potential of fractured basement. The 3D fracture modeling is done using the discrete fracture network (DFN) approach with image log interpretation and other fracture drivers serving as the main input. The DFN is upscaled to generate fracture porosity and fracture permeability properties in a 3D grid. The upscaled fracture porosity is used to estimate the petroleum initially in place (PIIP) for the prospects. Multiple 2D petroleum system modeling is performed where large fault throws are identified from seismic interpretation. The petroleum system study helps in identification of areas with most prolific hydrocarbon generation and expulsion centers, which, coupled with the cross-fault juxtapositions, are the main locales of charging for basement reservoir. Further analysis of all the elements of basement play (i.e., source, reservoir, seal, trap, and migration) is done, and prospective areas within the basement play are delineated with high geological chance of success.
Simplified analytical methods are used in 1D geomechanics workflows to predict the rock's behavior during drilling, completion and production operations. These methods are simplistic in their approach and enable us in getting a time-efficient solution, however it does lose out on accuracy. In addition, by simplifying equations, we limit our ability to predict behavior of the borehole wall only i.e. near wellbore solutions. Using 1D analytical methods, we are unable to predict full field behavior in response to drilling and production activities. For example, when developing a field wide drilling plan or preparing a field development plan for a complex subsurface setting, a simplified approach may not be accurate enough and on the contrary, can be quite misleading. A 3D numerical solution on the other hand, honours subsurface features of a field and simulates for their effect on stresses. It generates solutions which are more akin to reality.
In this paper, difference between a simplified semi-quantitative well-centric approach (1D) and a full field numerical solution (3D) has been presented and discussed. The subsurface setting considered in this paper is quite complex - high dipping beds with pinch outs and low angled faults in a thrust regime. Wellbore stability and fault stability models have been constructed using well-centric approach and using a full field-wide 3D numerical solution and compared to understand the differences.
In this study, it was clearly observed that field-based approach provided us with more accurate estimation of overburden stresses, variation of pore pressure across the field, changes in stress magnitudes and captured its rotation due to pinch-outs and formation dips. For example, due to variation in topography, the well-centric overburden estimates at the toe of deviated well at reservoir level is lower by 0.21gm/cc as compared to the 3D model. It is also observed that within the field itself stress regime changes from normal to strike slip laterally across the reservoir. In comparison to 1D model, considerable differences in stable mud weight window of upto 1.5ppg is observed in wells located close to faults. This is due to effect of fault on stress magnitude and azimuth. Stress state of 4 faults were assessed and all are estimated to be critically stressed with elevated risk of damaging three wells cutting through. However, a simple 1D assessment of stress state of faults at wells cutting through them, show them to be stable.
Moreover, the 3D geomechanical properties that are input into the numerical simulation also play an important role on the results. The algorithms and data used to populate the properties away from the well, need to be validated and calibrated with the well data, to predict reliable results. As the subsurface was quite complex, and well data was not sampled optimally, both horizontally and vertically, the selection and optimum usage of 3D trends also became crucial.
By comparing the differences between 1D and 3D solutions, importance of 3D numerical modelling over 1D models is highlighted.
Temperature logs have been used to monitor producing wells since the early 1930s. Normally, analysis of the temperature log is viewed as secondary to that of the spinner flowmeter, which gives flow velocity directly, and temperature is conventionally used only as an indicator of fluid entry/exit with the production logging tool (PLT). The main disadvantage of the PLT is that if spinner flowmeter data are not good due to tool problems, then flow quantification is jeopardized. Additionally, in recent years, the cost of production logging has increased considerably because many wells are now drilled horizontally through the reservoir, and the PLTs must be conveyed on coiled tubing or well tractors, and, in some cases (subsea wells), even this may not be possible. Consequently, alternative technologies become viable if they can be used for flow quantification using just temperature data. This paper presents a new flow quantification model using temperature data acquired using production logging or a distributed temperature sensor (DTS) system.
The model presented in this paper can handle multiple production zones with their zonal fluid properties as input to give corresponding zonal flow rates as output. The said model is applicable for single-phase oil and gas producer wells as well as water injection wells in both onshore and offshore environments. There are two modes of flow calculation for each answer product-steady state or transient. The model is integrated into easy-to-use software, and it has options for forward simulation as well as optimization. The forward simulation calculates temperature distribution along the wellbore for any given production profile, which is critical for model calibration for any reservoir. After the model has been validated for a reservoir, it can be used for zonal flow quantification using any temperature survey. The objective of the optimization option is to allow the user to fit the model output temperature curve to a selected temperature curve by means of a genetic fitting algorithm that will adjust one or two user-selected reservoir parameters, such as permeability, pressure, skin, gas-oil ratio (GOR), temperature, or water-cut, until a fit is achieved.
The model has been extensively tested against synthetic, literature and field examples and good agreements have been obtained, confirming the robustness of this novel approach.
Bordeori, Krishna (Schlumberger) | Gupta, Vaibhav (Schlumberger) | Sharma, Lovely (Schlumberger) | Narayan, Shashank (Schlumberger) | Talukdar, Dhurba (Oil India Ltd.) | Lama, Tshering (Oil India Ltd.)
Cased hole gravel pack (CHGP) is the most popular method for controlling production of formation sand in oil or gas cased hole wells. CHGP involves the packing of screen and casing annulus, and perforations to inhibit production of formation sand. Success of a CHGP depends on various factors such as perforation packing, cleanliness of completion brine, perforation strategy and minimizing drawdown. Quality of perforation packing aids in minimizing drawdown of gravel pack completions. This led to popularization of high-rate water packs (HRWPs), an evolved sand control method for cased hole wells. HRWPs involve pumping above fracture extension rate and placing gravels outside casing into the critical matrix. This paper discusses maturation process in design, execution, and evaluation methodology devised from a campaign of 16 HRWPs, which included two formation breakdown acid injections, one slim hole completion, two re-stresses and one top-off.
Naharkatiya fields of Oil India Limited, in Assam-Arakan basin are characterized with high degrees of unconsolidated formation sand. Elements of heterogeneity like formation sand ingression rate, PSD, mineralogy and well-profile in these two fields, where most of the HRWP treatments were executed, demanded case-specific pre-gravel-pack workover operations. Installation of screens and pumping of HRWP treatment presented many challenges, such as formation sand ingression, high circulation pressures, uneven slack/pull weights and issues in tool operations. All these challenges were tackled in unique ways and successful HRWP treatments were completed. A holistic approach was developed towards execution of a High Rate Water Pack treatment, by analyzing all interlinked elements such as perforations, cores, cement bond, reservoir saturation, water cut and offset well history. Post-treatment evaluation of HRWPs using bottomhole gauges identified a sequence of downhole events and potential issues during execution phase. Correlating each new HRWP candidate with learnings from previous ones allowed the operator to better plan workover steps towards execution of the sand control treatment. Contingency plans were devised to tackle issues learned from previous wells, and many were successfully tested in the campaign. Production rates and choke strategies were optimized by analysis of offset wells.
This paper presents data analysis of wells while correlating with their offsets. Post-treatment analysis has been discussed and correlations between suspected issues during execution with signatures in bottom-hole gauge data have been presented. Recommendation are further provided for drilling and completion operations. Evolution in design and execution process for case wells has been presented, which can be used as a reference literature for designing case specific sand control treatment program.
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.
Vertical Interference tests (VIT) are used to determine the hydraulic connectivity between the formation sand intervals. This paper showcases an innovative workflow of using the petrophysical log attributes to characterize a heterogeneous reservoir sand by making use of ANN (Artificial Neural Net) and SMLP (Stratigraphic Modified Lorentz) based rock typing techniques as well as image based advanced sand layer computation techniques.
Vertical interference test is either performed using a wireline formation testing tool with multiple flow probes deployed in a vertical sequence at desired depth points on the borehole wall or using a drill stem test configuration. Based on the test design, flow rates are changed using downhole pumps, which induces pressure transients in the formation. The measured pressure response is then compared with a numerical model to derive the reservoir parameters such as vertical permeability, hydraulic connectivity etc. The conventional way of model generation is to consider a section of reservoir sand as homogenous, which generally leads to over estimation or underestimation of vertical permeabilities. The technique proposed in this paper utilizes advanced logs such as image logs; magnetic resonance logs, water saturation and other advanced lithology logs to obey heterogeneity in the reservoir model by utilizing ANN/SMLP based rock-typing techniques. These rock types would be helpful in making a multi layer formation model for the VIT modeling and regression approach. The vertical interference test model is then used to determine the vertical permeability values for each of the individual rock types. The paper displays the workflow to utilize the rock type based layered formation model in vertical interference test modeling for a channel sand scenario.
Al-Bahar, M. (Kuwait Oil Company) | Al-Sane, A. (Kuwait Oil Company) | Bora, A. (Kuwait Oil Company) | Kumar, A. (Kuwait Oil Company) | Mendjoge, A. (Kuwait Oil Company) | Dhote, P. (Kuwait Oil Company) | Antonevich, Y. (Schlumberger) | Back, M. (Schlumberger) | Kassim, A. (Schlumberger) | Mason, D. (Schlumberger) | Sethi, M. U. (Schlumberger) | Siddique, E. (Schlumberger)
Management of oil and gas resources and reserves has always been complex process as the company’s portfolio consists of resource and reserves volumes with varying degrees of uncertainty and maturity levels of projects. Some of the hydrocarbon volumes are from resources that are highly uncertain and require technology imprevoments or breakthroughs. However, for strategy formulation of the country/company needs consideration of all hydrocarbon volumes that can generate value in the future. The prioritization of development strategies for its reservoirs based on rigorous technical and economic assessments while protecting the national interests is a challenging task.
Kuwait Oil Company (KOC) has been using multiple systems for both asset and business planning processes that is not optimized for faster turnaround. The proposed integrated and automated reserves management solution provided a structured environment for systematic economic evaluation and portfolio optimization. It facilitates the visualization of key reservoir parameters delivering full understanding of the forecasted reserves, production and economic potential of the entire company. It indentifies gaps between reserves and detailed development plans based on technical and commercial criteria. By Optimizing the project timing and economics results in reduction of budgetary expences, increase in portfolio revenue and greater confidence for the company. Ranking the investment opportunities helps in allocating resources appropriately amongst different projects in a systemic manner to ensure profitability of the company. This approach provides ease to KOC in modeling complex scenarios and quickly evaluate a wide range of different development strategies catering for risk and uncertainty
This paper describes current industry challenges in resource and reservoir management, and an integrated approach to reserves, economics and portfolio management envisioned for Kuwait Oil Company (KOC) which will assist in identifying optimal reservoir development options to meet any defined strategic goals. The results and benefits gained after deployment of pilot will also be explained in the paper. This integrated approach for optimization of Asset Action Plans is a unique solution and would prove beneficial for our industry.
Using optical fibers to instrument hydraulically fractured wells is becoming routine in US unconventional plays. Instrumented wells facilitate understanding of proppant distribution among perforation clusters and the inefficiencies of geometric fracturing and well planning techniques. However, converting fiber-optic data into proppant distribution requires management of high volumes of data and correlation of the data to factors such as well conditions, fracturing parameters, and temperatures. A user-friendly workflow for understanding hydraulic fracturing proppant and slurry distribution among different perforation clusters over time is presented. Ideally, slurry flow is equal between perforation clusters and, at least, constant in time, but the reality is very different. The interpretation workflow is based on proprietary algorithms within a general wellbore software platform and aims to greatly expedite the analysis. We propose using distributed acoustic sensing (DAS) data (in the form of custom frequency band energy (FBE) logs), distributed temperature measurements (DTS) and surface pumping data to obtain a quantitative analysis of proppant distribution within minutes, with various options for reporting and visualizing results. The software platform selected provides data integration, visualization, and customization of in-built algorithms. The new workflow enables users to upload DAS, DTS, flow rate, pressure, and other measurements and use customized algorithms to quantitatively analyze proppant distribution, enabling decisions in real time to optimize the fracturing operation. The validity of the approach is illustrated by a case study involving a well with 28 stages and four to five clusters per stage. The workflow is automated to provide results in real time, enabling quick corrective actions and significantly improving the efficiency and economics of hydraulic fracturing.
Primary cementing operations rank among the more important events that occur during a well's lifetime. The cement sheath plays a critical role in establishing and maintaining zonal isolation in the well, supporting the casing and preventing external casing corrosion.
For many years, the industry has employed strategies to promote optimal cement placement results. These strategies, collectively known in the industry as good cementing practices. Job execution is the key to insure success of the job based on the designed.
New technology that give us optimum execution evaluation (OEE) has been developed to enhance cement job execution by overlapping the design parameter over with the execution parameter real time. The OEE technology significantly improves cementing operations, enabling operators to monitor, control, and evaluate cement placement in real time. OEE combines job design data with acquisition data from both the rig and the cementing equipment to provide a more accurate representation of the job as it is being run.
In this paper, we present the process that we completed with detailed operational setup to allow us to monitor and record all parameters related to the cement job execution and the work flow implemented to be able to evaluate the cement job design and execution to achieve the required objectives. This study is also setting the basis to establish development of real time automated cementing advisory system.
Agrawal, Gaurav (Schlumberger) | Kumar, Ajit (Schlumberger) | Mishra, Siddharth (Schlumberger) | Dutta, Shaktim (Schlumberger) | Khambra, Isha (Schlumberger) | Chaudhary, Sunil (ONGC) | Sarma, K. V. (ONGC) | Murthy, M. S. (ONGC)
Objectives/Scope: XYZ is one of the marginal fields of Mumbai Offshore Basin located in western continental shelf of India. Wells in this field were put on ESP for increasing the production. Regular production profiling with traditional production logging was done in these wells to ascertain the water producing zones if any and do the subsequent well intervention if required.
Methods, Procedures, Process: In few deviated wells with low reservoir pressure, low flow rates and large casing size, massive recirculation was observed due to which spinner readings were highly affected. In such scenarios, quantitative interpretation with conventional production logging is highly difficult. Only qualitative interpretation based on temperature and holdup measurements can be made which might not completely fulfill the objective. In one of the deviated wells, massive recirculation was observed due to large casing size. Recirculation on ESP wells is generally not expected due to high energy pressure drawdown exerted on the well. Traditional production logging imposed difficulty in interpretation due to recirculation. Only qualitative interpretation was made from temperature and holdup measurements. Hence advanced production logging tool called Flow Scan Imager (FSI*) with 5 minispinners, 6 sets of electrical and optical probes, designed for highly deviated and horizontal wells to delineate flow affected due to well trajectory, was suggested for quantitative interpretation in such wells suffering with recirculation.
Results, Observations, Conclusions: In the next well, production profiling was to be done before ESP installation in similar completion as the last well. Therefore, huge recirculation phenomenon was expected in the well. FSI was proposed in this deviated well with recirculation for production profiling and also for finding out the complex flow regime inside the wellbore. FSI helped in proper visualization of the downhole flow regime with the help of multispinners and probes. Quantitative interpretation was made with the help of FSI data. Also, quantification was confirmed inside the tubing (lesser cross section area) where no recirculation is expected as the mini spinner does not collapse inside the wellbore. In traditional production logging, it is generally not possible due to the collapsing of full bore spinners inside tubing. Better understanding of the flow regime can be obtained with FSI than conventional production logging due to the presence of multiple sensors. Later interventions using FSI results have shown significant oil gains.
Novel/Additive Information: FSI was used in deviated ESP wells with recirculation for production profiling, accurate quantification, better understanding of flow regimes and to take improved well intervention decisions.