This paper attempts to answer a fundamental question pertinent to fracture characterization of unconventional basement reserves using rock mechanics & petrophysics; are open fractures in basements necessary critically stressed? Evaluation of naturally occurring fractures are critical for production as well as reserves estimation. In this regard, a study well was drilled in the basement section of the Cauvery basin to explore unconventional pay zones & characterize the contributing fractures by integrated Geomechanical & Petrophysical analysis.
A suite of open hole logs including the basic, acoustic and electrical borehole images were acquired and an integrated approach was taken, including geomechanical analysis to identify the contributing fractures. Standard petrophysical evaluation in basements was inconclusive and porosity quantification from fractures posed a major challenge. Image log analysis involved identification of conductive and resistive fractures in the gauged wellbore and combining Stoneley reflectivity further indicated probable open fractures. Following this, a geomechanical analysis was carried out to determine the current in-situ stress orientation/magnitudes based on observed breakouts. Finally a CSF study was done to check for fracture slip events.
Based on the integrated study of Petrophysics and Geomechanics, an optimized workflow was developed and the critically stressed fractures were identified. It was found that, while some fractures strike direction was different from the present day maximum horizontal stress direction (SHmax), in general, most fractures were indeed aligned to SHmax. To check the fluid flowing capability of fracture networks, formation tester was deployed in selective zones for testing and sampling. Successful hydrocarbon sampling from selective fractures with orientation not aligned to SHmax led to the validation of the current study. The results proved that while most critically stressed/open fractures did indeed contribute to flow, a smaller fraction of the naturally occurring fractures while contributing to flow, were not necessarily aligned to the in situ orientations.
The results present a discrepancy between observation and the expectation that open fractures are necessarily oriented parallel or nearly parallel to modern-day SHmax. This works highlights the fact that although paleo-stresses may influence the fracture networks, it is the contemporary in-situ stresses that truly dominate fluid flow and only through a detailed understanding of the critically stressed areas, can we come to a decisive conclusion that further improves overall recovery.
Reservoirs which produce under active water drive offer a significant uncertainty towards implementation of Chemical EOR processes. This paper describes a successful pilot testing of ASP process in a clastic reservoir which is operating under strong aquifer drive. The field has ~ 30 years of production history. The objective of the pilot was to understand response of ASP process in a mature reservoir, which is operating under active edge water drive. The build-up permeability of the reservoir is 2-8 Darcy with viscosity~ 50 cP. Salient key observations like production performance, incremental oil gain, polymer breakthrough etc. are discussed in this paper after completion of the pilot.
On the basis of laboratory study and simulation, ASP pilot was implemented in the field in 2010.The pilot was designed with single inverted five spot pattern and one observation well. The pilot envisaged injection of 0.3 pore volume (PV) Alkali-Surfactant-Polymer (ASP) slug, 0.3 PV graded polymer buffer followed by 0.4PV chase water. The pilot was meticulously monitored for production performance and breakthrough of chemicals. All the pilot producers have more than 20 years of production history. Base oil rate and water cut were fixed before start of the pilot, on the basis of test data which was used to monitor pilot performance. Interwell Tracer Test (IWTT) was conducted before starting of ASP injection so as to understand sweep in the pilot area. In addition, quality of injection water and chemical concentration in ASP slug was checked regularly to ensure best quality.
Significant response of the pilot was observed within 15 months of the start of the pilot which was published in 2012. This paper aims to describe the learning and conclusion after successful completion of the pilot. ~40-50% jump in oil rate was observed during the ASP injection period which sustained for 12-18 months. However preferential breakthrough of ASP slug in one of the producer impacted the incremental oil gain. The preferential breakthrough of polymer was due to presence of high permeability streaks which was rectified by profile modification job. In addition, strong aquifer movement was experienced during ASP injection which leads to rise in water cut of a pilot well. However, the pilot well was restored through water shutoff jobs. After completion of ASP and mobility buffer, a cumulative incremental oil ~28000 m3 was obtained. Cumulative incremental oil gain is in line with simulation studies prediction. 12-14% decrease in water cut was observed which sustained for ~ 6-18 months. Regular monitoring of produced fluid indicated breakthrough of polymer and alkali in 2-3 producers. During the pilot, produced fluid handling issues like tough emulsion formation, lift malfunctioning etc. was not observed. These collective observation indicated success of the ASP pilot project.
There are very few case histories of successful ASP pilot implementation are available, in which the reservoirs has been operating under active aquifer drive. Learning of this ASP project can be taken forward for expansion of ASP flood and also designing of ASP pilot/commercial projects for analogous reservoirs.
Foaming in absorber column for sour gas treatment using amine is a common problem which adversely affects column performance leading to reduction in sales and fuel-gas production and solvent loss. Mostly antifoam injection has been a common method to counter the foaming, large dosage and frequent dosing of antifoam many a times aggravates the problem. This study details an alternative technique based on pressure pulse mechanism to control foaming in one of ONGC's gas sweetening plants.
One of ONGC's amine based sour gas sweetening plants faced severe foaming problem frequently. The feed rate is 200 kscm/hr and absorber column operating pressure is 51 kg/cm2. The experiment utilizes the property of surface tension which fluctuates with change in pressure of the system leading to foam collapse. The experimental procedure involved varying the sour gas feed rate, thereby creating pressure pulse inside the absorber column. Differential pressure across the column which is an indicator of foaming tendency is then monitored and controlled within 1.0 kg/cm2 and recorded for establishing effectiveness of the method.
It is observed that by providing a number of cycles of pressure pulse in the absorber, the differential pressure stabilizes gradually which indicates collapse of foam. It shows that whenever there is increase in feed, expansion of bubble takes place which provides high interfacial liquid-vapour contact. On the other hand whenever there is decrease in feed rate, compression of bubble takes place which provides low interfacial liquid-vapour contact. Surface layer surrounding the bubbles in a foam acts as a membrane or skin that can stretch or relax in response to change in pressure and gives a mechanical shock which breaks the bubble. The increase of size ultimately leads to instability and break-up of the upper surface and releases the liquid holdup. Hence by using feed rate spikes, the pressure of the bubble is pulsed to higher levels and returned to substantially the original level. This cycle continues for a selected number of times so that this pressure pulse travels through the liquid and bubbles and affects its surface tension. This results into a transition phase which in very high energy level breaks the bubble and releases the gas and decreases the liquid hold up and controls the foaming phenomenon.
This paper will gives an insight into a novel methodology of mitigating foaming problem in a sour gas treating absorber just by varying the feed rates in a controlled manner. This technique eliminates the need for injecting antifoam agents which in turn will reduce the operating expenditure of the plant. Adverse impact on environment due to excessive use of antifoam agent is also minimized.
As the oil and gas industry is moving towards digital oil field, the selection of leak detection system (LDS) has become more crucial. Early detection of leaks not only saves environment from Hazardous hydrocarbons but considerable loss in production is also saved. This paper discusses about both internal and external LDS and its applicability for onshore and offshore fields. This paper will ease the selection process of LDS for green and brown fields of both offshore and onshore installation.
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.
Chakraborty, Srimanta (Baker Hughes, a GE Company) | Panchakarla, Anjana (Baker Hughes, a GE Company) | Deshpande, Chandrashekhar (Baker Hughes, a GE Company) | Malik, Sonia (Baker Hughes, a GE Company) | Singh Majithia, Pritpal (ONGC) | Chaudhary, Sunil (ONGC) | Murthy, AVR (ONGC)
Conventional volumetric analysis has its own limitations & challenges to characterize fluid types in complex clastic reservoirs. Presence of shale and radioactive minerals in sandstones makes the evaluation more complicated compared to clean reservoirs as uncertainty become higher to ascertain grain density & total porosity. Delineation of pay zones (heavy oil bearing) & estimation of saturation become more uncertain due to reservoir complexities.
Elemental spectroscopy log can provide real time grain density, TOC (Total Organic Carbon) and mineralogy for complex reservoirs (radioactive sand). However, to determine the fluid type and porosity in this type of reservoir, Nuclear Magnetic Resonance (NMR) would be the best choice due to its capability of recording simultaneous T1 (Spin-lattice relaxation time) and T2 (Spin-Spin relaxation time) including diffusivity measurement sequences. Compare to the traditional 1D T2 spectrum based interpretation methodology; A new approach of using constrained 2D NMR inversion, enhances the capability to discern different fluid phases by mapping proton density as a function of T2 relaxation time (T2int) in the first parameter dimension and diffusion coefficient "D" (or T1 relaxation time or T1/T2app ratio) in the second parameter dimension. An integrated approach is used by combining NMR and Elemental spectroscopy results to reduce formation evaluation uncertainties in heavy oil reservoirs.
Successful integration of NMR, Elemental Spectroscopy Log with Image and Acoustic results helps to understand reservoir properties in study area. The advantage of using constrained 2D NMR over conventional 2D NMR reduces the uncertainty of responses between Clay Bound Water (CBW) and heavy oil, which has similar T2 relaxation mechanism. Integration of Clay volume from Elemental Spectroscopy measurements in constrained 2D NMR helps to differentiate the heavy oil and clay bound water responses. Furthermore, the combination of NMR & Elemental Spectroscopy results helps to segregate the existence of heavier oil & lighter oil components in the reservoir. Based on these results, potential hydrocarbon zones was identified and successful testing attempts were made.
This paper shows an approach of using constrained 2D NMR results over conventional 2D NMR to overcome reservoir uncertainties & to identify potential pay zones.
Saumya, Sachit (Schlumberger) | Sarkar, Sujit Kumar (Schlumberger) | Singh, Juli (Schlumberger) | Kumar, Ajit (Schlumberger) | Agarwal, Gaurav (Schlumberger) | Khambra, Isha (Schlumberger) | Vij, Jitesh (Schlumberger) | Das, Bhaswati (Schlumberger) | Shedde, Preetika (Schlumberger) | Majumdar, Chandan (Schlumberger) | Pabla, S (ONGC)
Drilling is carried out in the very early stage of the well and it is critical for ensuring smooth execution of every aspect of well construction such as faster drilling, better hole cleaning, superior logging, running casing efficiently, maintaining wellbore integrity and achieving economic production. This paper will demonstrate the significance of best drilling practices to achieve good wellbore geometry, which has a profound effect on total well construction and production time and cost and sometimes even determine the success of the well.
Poor wellbore geometry, because of improper choice of drilling system i.e. mud motor or rotatory steerable, is generally related to the washed out and/or spiraled wellbore. Washed out hole is recognized by using calipers, however, the hole spiraling is difficult to detect at the early stage of the well. In spiraled holes, it becomes virtually impossible to get a good cementing job done. The poor cementing conditions behind the casing are identified using ultra-sonic images or high amplitudes values of CBL/VDL. These channels behind casing are, a clear threat to production and life cycle of the well. It is widely assumed that the squeeze jobs are an option to improve cement behind casing, however, it does not hold true in case of a spiral borehole. This paper compares the wells, drilled with different drilling system and their impact on the wellbore geometry. It also exhibits the aftermath effects on wellbore construction, well integrity and production.
The basal clastic sand (BCS) unit is derived from a granitic basement and forms the lower part of the Mumbai High field. Oil indicators in unconventional reservoirs, such as basement and BCS, were explored here before 1987; however, these reservoirs were not targeted for more than two decades after drilling the first exploratory well in 1989. Huge potential in BCS resources remained untapped, and monetizing these resources became possible because of extensive hydraulic fracturing design optimization for these layers.
Previously, acid stimulation treatment failed to provide any improvement in the BCS reservoir. Because BCS is derived from a granitic basement and contains clay minerals (kaolinite and chlorite), heavy minerals, siderite, pyrite, hematite, etc., it is difficult to obtain gains using acid stimulation because of poor leakoff and associated reaction kinetics. However, stimulation using hydraulic fracturing with proppants proves to be the ultimate productivity enhancement tool and is the prudent alternative.
The first hydraulic fracturing attempt in BCS was performed at Well B in 2013 and was unsuccessful because proppant placement and admittance are extremely difficult in these layers. High net pressure and complex branch growth were identified to be the core causes of premature screenout in this layer. Post-treatment pressure evaluation indicated propagation of short fissures and fractures leading to a complex fracture plane that reduced overall fracture conductivity.
Subsequently, Well A was diverted from the original location, completed in the BCS reservoir, and selected as a candidate for proppant fracturing. The stimulation strategy was designed to meet stimulation challenges of the BCS formation. Perforation designs were revised to reduce near-wellbore tortuosity and perforation friction. After perforating, the well was treated with an acetic acid cushion against the target zone. A new fracturing treatment design based on slug and sweep, where the slug stages were increased, was used to control excessive near-wellbore complex fracture growth. Aggressive pumping rates and high conductivity proppant size and concentration were designed to help increase stimulation efficiency. These unconventional modifications aided successful placement of the fracture plane in the BCS reservoir in Well A.
Well A initially produced 202 BOPD; however, production declined because of the tight nature of the BCS reservoir. Later, the well produced 100 BOPD with gas lift. After hydraulic fracturing treatment for this well was successfully performed, as per the modified design, the production increased to 1,580 BLPD with 100% oil and no artificial lift using a 1/2-in. choke. This paper highlights design considerations, execution results, and post-treatment evaluation of this extremely challenging BCS volcanic rock and can be viewed as a best practice for addressing stimulation challenges in similar volcanic reservoirs in other fields.
Carbonate reservoir are associated with various porosity types e.g., moldic, vuggy, fenestral, intergranular, intercryatalline, skeletal, stylolitic, fracture etc. Flow characters associated with different porosity types vary extensively. Therefore, characterization of carbonate reservoir warrants identification and quantification of distribution of different porosity types in the carbonate body. In this paper a robust algorithm has been developed by integrating Differential Effective Medium Theory and Self Consistence Approximation Theory to predict porosity partition in carbonate reservoir. Application of this algorithm in a carbonate reservoir from Mumbai Offshore Basin yield porosity partition logs that is in tune of the geological understanding and information obtained from core/SEM/petrographic images. This algorithm takes mineral volumes from processed well log and travel time from sonic log as the input, which are readily available for almost all the wells.
Presentation Date: Wednesday, September 27, 2017
Start Time: 1:50 PM
Presentation Type: ORAL
Nanotechnology has become the buzz word of the decade! The precise manipulation and control of matter at dimensions of (1-100) nanometres have revolutionized many industries including the Oil and Gas industry. Its broad impact on more than one discipline is making it of increasing interest to concerned parties. The Nanotechnology applications have pierced through different Petroleum disciplines from Exploration, to Reservoir, Drilling, Completion, Production and Processing & Refinery. Nanotechnology also strikes the stage of production enormously to enhance the oil recovery via molecular modification and manipulate the interfacial characteristics. Moreover, in a very similar fashion, it provides novel approaches to improved post production processes. The present paper provides an overview of the various types of nanoparticle which enhance the recovery of oil. “Polysilicon” nanoparticle can alter the reservoir wettability and reduces interfacial tension resulting in additional recovery of entrapped oil from pores. Nanoparticles derived from transition metal oxides namely NiO, Co3O4 and Fe3O4 adsorbs asphaltenes from heavy oil which reduces the viscosity of heavy oil and enhances oil recovery.