Gupta, Shilpi (Schlumberger Asia Services Ltd) | Sinha, Ravi Kumar (Schlumberger) | Kumar, Ajit (Schlumberger) | Pandey, Arun (Schlumberger) | Ogra, Konark (Schlumberger) | Verma, Vibhor (Schlumberger) | Bisht, Pushkar (Oil & Natural Gas Corp. Ltd.) | Hinge, P.P. (Oil & Natural Gas Corp. Ltd.)
Production logging (PL) has long been in use in the industry for evaluating the well performance for making strategic decisions. However, understanding the production profiles is challenging in complicated flow regimes and complex wellbore completions. To increase productivity in underperforming sick wells, electrical submersible pumps (ESPs) are generally effective options if planned and installed judiciously. This unique case study validates the application of production logging in planning and executing workover operations and by diagnosing the issues for suboptimal production performance of an ESP completed well.
Located in XYZ field of Mumbai offshore in India, Well G has been in production since October 2006, predominantly producing at the rate of 900 barrels of oil per day (BOPD) with 10% water cut (WC). After producing for 2 years, well production declined significantly to 600 BOPD. PL data were used efficiently to increase productivity at three different stages during the life of the well. In the first stage, PL played a key role in mapping the zonal production profile. On the basis of these data, an acid job was suggested, which increased production by 300 BOPD. In the second stage, when the production rate again declined to 600 BOPD within a year, PL played a key role in defining perforation and re-perforation strategy by identifying the silent zones and helping to plan ESP installation when the well was incapable of lifting fluids to surface. This led to an increase of only 50 BOPD as compared to the expected increase of 600 BOPD. During the third stage, PL combined with a Y-tool was instrumental in diagnosing a mismatch between ESP design capacity and reduced reservoir deliverability, which was the key reason for the unexpected underproduction. On the basis of the diagnosis, an acid job was suggested to increase well deliverability. Following the acid job, production increased by almost 75% to 1034 BOPD without changing and damaging the ESP.
This case study is of interest to plan workover operations and to diagnose production problems using PL to optimize production in ESP completed wells with changing reservoir productivity.
Ogra, Konark (Schlumberger) | Chandra, Yogesh (Oil & Natural Gas Corp. Ltd.) | Pandey, Arun (Schlumberger) | Verma, Vibhor (Schlumberger) | Kumar, Ajit (Schlumberger Asia Services Limited) | Sinha, Ravi (Schlumberger Asia Services Limited)
Production logging traditionally has been used to describe the flow characteristic of a well. Over the years with the advancement of the technology, for the techno economic success, deviated and horizontal wells have been drilled. Application of highly deviated and horizontal wells for field development primary recovery is now a worldwide practice.
Diagnosing production problems in a near horizontal environment is a herculean task; complex flow regimes in highly deviated well aggravate complications. At the same time, with advancement in completion system design, it has become imperative to evaluate the effectiveness of the new completion design. Unfortunately traditional production logging techniques have not been successful in these conditions.
One of the key issues in diagnosing production problems is detecting and distinguishing hydrocarbons in high water cut wells with water phase flowing as continuous medium at the low side and dispersed hydrocarbon phase at the high side of wellbore. Technologies like the digital entry fluid imaging tool and gas holdup optical sensor tool have proven to provide accurate results. For horizontal and highly deviated wells where recirculation, crossflow, and phase segregation further complicate the flow behavior, complete imaging of the wellbore is needed to characterize the wells.
In brownfield scenario, the complications aggravate and may require real-time decision making and intensive data analysis. Some of the typical brownfield issues are scale buildup due to immense water injection for pressure support, which is required for efficient oil displacement, complex fluid flow regime, recirculation due to insufficient lift, and casing damage resulting in unwanted formation water entry.
The study provides the most prolific summary and guide for case studies, success stories and lessons learned from the Mumbai High field in the last decade; evolution of the production logging tool from the most standard unit to multipoint digital entry fluid imaging, gas holdup optical sensor tools to identify and distinguish between the three fluid phases. The paradigm shifts towards the key technologies like flow scan imager to evaluate the complex borehole fluid behavior, flow regimes identification is also presented in this paper. The results derived are indispensable for future well placement campaign
The Nandasan field discovered in 1969 is a multi-layered reservoir in western part of India and producing oil & gas with little problem as it is having good porosity and permeability. Deeper multi layered mehsana formation comprises of 45% silicon, 9%aluminium, 18%iron, 0.23%calcium, 0.47%potesium ,12%other heavy metal having montmorillonite, Kaolinite and Chamosite clay. Several mud acid treatments have been performed successfully in the shallow depth but the same is not quite effective for deeper pay zone (1700-1800m). Core flow study with mud acid through indicates some precipitation resulting in formation damage and its success in field is limited. Therefore, greater understanding of down hole chemistry and assess the extent of the much slower secondary and tertiary reactions under reservoir conditions is critical for the acid treatment success. Monitoring of metallic ion generation during / after various acidizing treatments gives insight into actual chemical acid-spending processes that occur in the formation.
In the laboratory study, four type of different acid system has been tried with representative core and the resultant dissolution and metallic ion generation processes has been monitored for 3 hours using atomic absorption spectrometry followed by core flow study. Aluminium, Silicon and Iron complexes precipitation observed during secondary and tertiary reaction has been successfully tailored by changing the ratio of HCl:HF and other additives in traditional mud acid system. Results show that RA-1(AlCl3+ HF) acid is little reacting with Silicon whereas RA-2(Phosphonic acid+ ABF) creates Silicon & Calcium precipitation since beginning, thus not suitable. Similarly, RF(HCl+HBF4) creates Silicon precipitation after 150 min in tertiary reaction, whereas, MHF(HCl-HF) acid creates Al precipitation in secondary reaction and Iron precipitation since beginning that is resolved by increasing HCl:HF ratio and adding iron sequestering agent. Core flow study confirms the success of MHF by observing permeability improvement, therefore, suitable for matrix acidization of mehsana formation.
This paper presents a new, effective and economical technique to assess and understand the extent of secondary & tertiary reactions under reservoir conditions that will help in additives selection and making acid formulation for effective matrix acidization of sand stone reservoir that leads to improved field practice.
India has sixth largest coal reserves in the world and estimated to be at 206 billion tons and it ranks 10th in CBM resources having 4.6 TCM methane gas covers 20,000 km2 of area. The CBM reservoirs is multilayered, heterogamous, naturally fractured (cleats) and having fine micro pores. Bulk porosity of the coal is very small (<5%), the initial gas saturation is very low (<10%) and most of the gas in coal (>90%) is adsorbed in the micro pores of coal matrix and under saturated condition. Rapid dewatering is needed for reduction the reservoir pressures below critical pressure for desorption of gas from coal bed. Therefore, conventional / horizontal well with fracturing, multilateral well to cover many zones in CBM is being opted for economic exploitation. More than 60 no of conventional and horizontal/multilateral wells are drilled so far and many of them are completed with hydro-fracturing.
As coal is a weak substance and small pressure can cause the coal to fail and generate fines, hence enormous coal fines are normally produced during production (in case of high draw-down) and during hydro fracturing of coal seams. In some fracturing job, fines generation & migration reduces the fracture length and conductivity lead to reduced dewatering. Similarly, in multilateral well of CBM, coal fines are accumulated at the heel of the well in case of high draw drawdown and creating the restriction in dewatering and gas production.
In view of the above, innovative pre-fracture treatment technique with innovative formulation (Mixture Nonylphenoxy polythyleneoxide and Nonylphenoxy polythyleneoxide in the ratio of 1:2 with 0.5 % biopolymer) is developed & successfully tested in laboratory to change the wettability of the coal fine by making it hydrophobic to hydrophilic. Coal fines can easily come out with water based fluid during pre-treatment, hydro-fracturing and multilateral wellbore cleaning.
India has sixth largest coal reserves in the world and estimated to be at 206 billion tons and it ranks 10th in CBM resources. Prognosticated CBM resources in India is 4.6 TCM (162 TCF) and estimated 'in place' about 2,000 BCM in about 20,000 km2 of area. A recoverable reserve is about 800 BCM. To pursue the non-conventional energy exploitation, ONGC initiated CBM exploration activities by drilling R&D wells in Durgapur area of Raniganj coalfield in 1995-96 and further classified Indian Coal Basins into 4 categories Jharia, Bokaro, Raniganj and North Karanpura basins, which is most prospective.
Heera field is located 70kms south-west of Mumbai city and 140 kms south-east of Mumbai High at an average water depth of about 50m. The field was put on production in November '84. The oil production is mainly from Bassein, Mukta (carbonates) and Panna (basal clastics) formations. The general dip of the field is towards west. The field produced under depletion drive for about six years till Sept. 90. By this time the reservoir pressure dropped to 1300psi from 2150psi and the field experienced sharp decline in production. Water flooding in Bassein formation started in September '90. The production stabilized for some time and then again started declining with a sharp rise in water cut. Current average oil rate from the field is 55,892 bopd with water cut of 56% and GOR 145 v/v through 152 producing strings. The average water injection is 1,36,800 bwpd.
The present study aims to identify injection water breakthrough patterns in the producers of Bassein formation of Heera field. The study area is the upper part of mid- Heera field comprising of wells of platforms HD, HQ, HR and HA. The sudden rise in high water content could be due to the breakthrough of injection water in to the producers. Spider diagrams and contour maps were used to interpret the injection water breakthrough patterns in the study area.
Areal distribution pattern as indicated by contour maps of different ions in the study area suggest that there is more influx of injection water in the wells lying on the rising flank of the basin. In the down dip effect of injection water is less. Wells of HA and HD lying on the eastern side are more affected by influx of injection water than wells of platform HR and HQ.
Continuous withdrawal of hydrocarbon from reservoirs over the years normally results into a decline in the oil production rate with concomitant increase in water cut. Same phenomenon has been observed in the Mumbai High fields. To sustain oil production water injection is normally resorted to for pressure maintenance/reservoir drive. High water cut is one of the reasons for decline in oil production in the fields. Heera field is also experiencing rise in water cut after the start of injection. It is important to know if the rise in water cut is due to injection water breakthrough or some other factors. This is also crucial to know so that necessary steps could be taken to maintain better reservoir health. The study is intended to identify the wells where increase in water cut could be attributed to injection water breakthrough.
Natural tracers are ionic species naturally present both in the formation water and injection water. Prerequisite for a species to be used as natural tracer is the vast difference in the concentration of some of the ions in both the waters. Natural tracer technique 1-3 of identification of the breakthrough involves comparison of the concentration of different ions in the produced water and original formation water (OFW) and Injection /sea water (IW) with respect to the natural tracers like: sulphate, magnesium, strontium, & bicarbonate ions. The concentration of sulphate, magnesium ions and salinity value of IW are more than that of original formation water while the strontium and bicarbonate concentrations of IW are much less than that of OFW. An increase in sulphate and magnesium concentrations combined with a decrease in strontium & and bicarbonate ions concentration indicates the influx of injection sea water into the producers. The results of water analysis of injection and produced water is plotted in spider diagrams and contour maps to understand the extent of influx of injection water in the well as well as the pattern of injection water influx in the study area.