Al-Wahaibi, Yahya (Sultan Qaboos University) | Al-Hashmi, Abdul-Aziz (Sultan Qaboos University) | Joshi, Sanket (Sultan Qaboos University) | Mosavat, Nader (Sultan Qaboos University) | Rudyk, Svetlana (Sultan Qaboos University) | Al-Khamisi, Sami (Sultan Qaboos University) | Al-Kharusi, Thuraya (Sultan Qaboos University) | Al-Sulaimani, Hanaa (Petroleum Development Oman)
The need for a better understanding of surfactant/polymer adsorption, its quantification, and its influence on the physiochemical properties of reservoir rock can be crucial in the application and optimization of ASP flooding for EOR. This study is aimed to quantify surfactant/polymer adsorption onto Berea sandstone and reservoir rock. Surfactant and polymer adsorption onto crushed core samples and their consequent influence on surface morphology and wettability alteration were investigated. In addition, the effect of the presence of a pre-adsorbed polymer or surfactant layer on the subsequent surfactant or polymer adsorption was investigated. The chemicals used were a partially hydrolyzed polyacrylamide and an Internal Olefin Sulfonate surfactant. Polymer and surfactant concentrations in solutions were measured using total organic carbon (TOC) analyzer and potentiometric titration, respectively. Crushed core samples were analyzed for clay content and minerals by X-ray powder diffraction (XRD). Contact angle was measured on glass slides that has been incubated in brine, polymer and surfactant solutions for brine/hexadecane and brine/crude-oil systems. Amott tests were performed to quantify the wettability alteration due to brine, polymer and surfactant solutions using reservoir oil and core plugs. Results show that polymer and surfactant adsorption follows Langmuir adsorption isotherms. The polymer adsorbed amount on crushed reservoir core was around 450 mg/100g at the plateau region using the synthetic brine (salinity of 1% and pH of 8). Surfactant adsorption on crushed Berea core and crushed reservoir core at the plateau region were 700 mg/100g and 400 mg/100g, respectively. The higher surfactant adsorption on Berea cores is attributed to its higher clay and calcite content compared to the reservoir core. Contact angle (CA) on glass slides increased against both hexadecane and crude oil after surfactant adsorption onto the glass surface, which indicates that wettability-altering effect of surfactant on the surface to be more oil-wet. However, the CA remained nearly unchanged after polymer adsorption. Glass slides treated with polymer adsorption followed by surfactant adsorption ‘P-S’ and surfactant adsorption followed by polymer adsorption ‘S-P’ changed towards more oil-wet indicating higher influence of surfactant adsorption on wettability alteration. The FESEM images showed different adsorption pattern for surfactant treated slides. The Amott index of original brine/oil system was altered from 0.87 to 0.67 and 0.50 for polymer/oil and surfactant/oil systems, respectively. Hence, surfactant shows a pronounced influence on altering the wettability of the original reservoir rock to be less water-wet.
Weathered and fractured crystalline Basement emerged as the important unconventional play in the Barmer Basin. Natural fractures play a very significant role in the migration and hydrocarbon storage in crystalline fractured and weathered crystalline Basement reservoirs. Complexity and heterogeneity of the fracture network in the basement is a challenge to the geoscientist. This requires precise fracture characterization which is very significant for estimating the hydrocarbon potential as well as development of these reservoirs. A novel approach of integrating the seismic geometrical and stratigraphic attributes, with the borehole image logs and core data were found to be useful to characterize fractured and weathered crystalline basement reservoir in the Saraswati Field located in the eastern margin of Barmer basin. Seismic data derived Ant track volume calibrated with the core and bore hole image data has predicted NNW-SSE and NE-SW trending natural fractures information. Acoustic impedance and RMS seismic amplitude attributes identified the zones of intense fractured and weathered Basement. Assessment of the natural fracture network helped for appraising the Basement discovery as well as for designing the optimal well path for intersecting the maximum number of fractures for better reservoir performance.
This paper aims to present the use of organic acid system for matrix acidization. When multiple minerals are present, they can create more formation damage and pose a challenge for acid treatments. In such cases, the paper proposes how a successful treatment can be designed.
Frequent acidizing operations are carried out in western onshore field of Oil and Natural Gas Commission (ONGC). It was observed that some wells were not responding effectively. To get more effective stimulation activities, a methodology was developed, under whichthe first step was to obtain the data related to well details and lithology, and second step was to obtain quantitative mineralogical data using (XRD).
Based on the above methodology it was found that the formation contained large amount of chlorite and other minerals, and that high concentration of HCl can create irreversible damage to this. To avoid this potential damage by HCl preflush, it was proposed to use organic acid preflush instead. Organic acid was proposed because of slow reaction rate, better result in presence of high iron content, better application in high bottom hole temperature etc compared to HCl. Organic acid, and HF were used as mainflush followed by overflush. This organic acid system was used in water injector well of the same formation.
Well head pressure and pumping rate data was recorded for well A and using that matrix acidization evaluation techniques were applied to the wells to quantitatively analyze the effectiveness of stimulation treatment. The same acid system was used for well B and a positive result was observed. Effectiveness of this result, of well A, was compared with previous operations where organic acid was not used. Same procedure of treatment evaluation was carried out and reduction in skin factor was calculated.
Currently most of the operations are done in the same fashion, where most of the operational problems are not counted in while planning initially. This paper will give an insight on the optimization of such operations in Horizontal Wells and especially wells with an angle more than 90°.
Poptani, R. V. (Cairn India Limited) | Mishra, L. (Cairn India Limited) | Gupta, A. K. (Cairn India Limited) | Saurav, S. (Cairn India Limited) | Singh, C. K. (Cairn India Limited) | Agrawal, N. (Cairn India Limited) | Patel, N. (Cairn India Limited) | Hammond, P. (Cairn India Limited)
Bhagyam field is located in the prolific Northern Barmer Basin in Rajasthan, India. It has nearly 110 producers and some of these wells have limited pressure support and are geologically distinct from the rest of the field. These wells are flowed intermittently according to a pre-defined cycle based on flowing bottom-hole pressures to optimise their production. Various stimulations have been attempted to increase near wellbore productivity. However, these have largely been unsuccessful. A further restriction is posed by the completion of these wells on Progressive Cavity Pumps (PCPs) as the artificial lift method which inhibits the use of acids and aromatic compounds.
This paper illustrates the successful trial of surfactant stimulation in increasing the productivity of these wells. Surfactants were considered as an alternative technique for stimulation as they pose no harm to the PCP elastomers. In addition to this, they help alter the wettability in the mixed wet to oil wet reservoir of Bhagyam field. The stimulations were designed to get the maximum penetration and were bull-headed from surface. This paper also discusses the unsuccessful stimulations carried out prior to field trial of surfactant stimulations and the studies done in the field to understand the damage mechanism behind low productivity/productivity decline. More than 10 wells (both low PI wells and intermittently flowing wells) have been successfully stimulated with surfactants till date in the field and have helped substantially in sustaining the overall field production.
Singh, Parvinder (Oil and Natural Gas Corporation Limited, India) | Lal, Kishori (Oil and Natural Gas Corporation Limited, India) | Rastogi, Ravi (Oil and Natural Gas Corporation Limited, India) | Joshi, C. S. (Oil and Natural Gas Corporation Limited, India) | Sinha, M P (Oil and Natural Gas Corporation Limited, India)
This paper provides a review of some of the best practices and case study of Agartala located in the northeast end of Indian continent at Tripura Asset and characterized by high pressure well. It elaborates on the design, execution and evaluation of the rheological hierarchy of mud, spacer and cement slurry to improve well integrity. Optimizing the density hierarchy for wellbore fluids has been a routine while achieving a proper rheological hierarchy have been compromised due to tedious testing and sometimes limitations in the field. Establishing appropriate rheological and friction pressure hierarchy prevent fluids (mud-spacer-cement slurry) intermixing especially in deviated and horizontal wells.
The selection of proper spacer and designing formulations with chemical compatibility with drilling fluid and cement slurry is very crucial and challenging. For better mud displacement the down hole forces imposed by the circulating fluids in well have to be sufficient to overcome the yield stress of any vicosified or partially dehydrated drilling fluids in hole. Weighted spacers are between the chemical means buoyancy effect on mud removal. The volume, rate and viscosity of spacer must be sufficient and carefully designed to prevent intermixing.
Rheological modeling can be determined by using fluid friction chart and cementing software. It is not always possible to accomplish the turbulent flow. Therefore, a rheological model was developed to accomplish the ideal viscosity hierarchy by optimizing the spacer formulation design. Optimum rheological hierarchy occurs where the viscosity profile of a spacer system is higher than the viscosity profile of drilling fluid and lower than the cement slurry.
In order to achieve this, An extensive laboratory testing was performed for compatible rheological modeling with mud-spacer-cement slurry (at surface temperature 27 Deg C & 80 Deg C) on rotational viscometer as per the procedure of API RP 10B-2. The water-based weighted spacer system, with density 1.85 g/cc was modeled to temperatures up to 80 Deg C and provided proper suspension properties, plays a significant role in achieving great displacement efficiency, wellbore clean up, effective zonal isolation. The volumetric proportions of the cement slurry/spacer and spacer/mud admixtures were prepared withvarious ratio: 95/5, 75/25, 50/50, 25/75, and 5/95. Rheological compatibility of fluids (cement & spacer and mud & spacer) assessed by calculating the R-Index Value (R). A mathematical modelling was also developed and applied to predict the rheology at elevated temperature by regression analysis/ trendline to assist on job rheological hierarchy maintenance.
Results obtained from field case study show the improvements in CBL-VDL recorded after cementation showed excellent result (02 to 07 mV) against zone of interest and added values such as ideal fluid compatibility, better displacement efficiency, friction pressure hierarchy and effective zonal isolation.
Kuwait Oil Company (KOC) launched a Project Gate System (PGS) program in 2010, which resulted in the development of the KOC PGS Process. The PGS Process was implemented in 2012, and has been applied to surface facility capital projects only. However, subsurface projects were excluded from the PGS, at that time.
In order to also improve the drilling of wells and facilitate the attainment of forecasted production targets efficiently and on time, a study of the development and implementation of a similar PGS Process for the delivery of wells was requested, in 2013. The study concluded that a parallel Well Delivery PGS (WD PGS) Process should be developed based on IOCs' and NOCs' best practices for well delivery, KOC's experience with the PGS Process, and the fit-for-purpose requirements of the concerned KOC stakeholders in all business Directorates.
In this paper, we will start by describing the way well delivery projects were handled in KOC prior to implementing the new system. Next, we will explain how the fit-for-purpose KOC WD PGS was developed and the "change management" efforts that took place to overcome the existing practices and to instill the new process. Finally, we will showcase the KOC WD PGS, as the output functional process. It is assumed that the reader possesses general understanding of the stage gate system for project management.
A case study on the effect of reservoir heterogeneities and reservoir model uncertainties on prediction versus actual field behavior and efforts being taken to improve oil recovery in Bhagyam field is presented in this paper.
Bhagyam field is the second largest onshore oil field in RJ-ON-90/1 block, Rajasthan India. The main reservoir has large variations in rock and fluid characteristics. The reservoir porosity range between 20% to 30%, and the maximum in-situ permeability ranges up to 30 Darcies, although the average permeability is 3 Darcy. The in-situ viscosity of crude oil ranges between 20 and 400 cP. The commercial production from the field started in 2012 at an initial rate of 15,000 bopd; the field attained production of ~25,000 bopd, although the envisaged production was 40,000 bopd as per the Field Development Plan (FDP). Based on the drilling and production performance of wells, a significant gap between actual and reservoir model based predictions was observed due to various reservoir uncertainties and complexities. Some of the key factors impacting the overall performance include lower effective permeability, higher oil viscosity, lower transmissibility, and wellbore issues.
Based on the large gap observed between predicted and actual field data, it was estimated that a much denser well spacing was required to achieve recovery estimated in the Field Development Plan. Coupled with a very unfavorable mobility ratio (due to the high in-situ oil viscosity), the water breakthrough was more rapid and widespread early in the production life of the field. Therefore, it was not possible to achieve the peak production rate and recovery in the FDP, even with the drilling of additional wells. The oil production has continued to decline with increase in water cut.
The field is currently producing around 14,000 BOPD with 88% water cut. The reservoir pressure is being maintained through current average water injection of more than 100,000 barrels per day. As of the time of writing, approximately 7% of the initial oil in place has been produced from the field. In order to maximize incremental oil recoveries over waterflood recoveries through improvement in sweep efficiency, various reservoir studies have been carried out to evaluate the feasibility and benefits of implementing a suitable chemical EOR technique in the field.
The case study is a useful reminder of how heterogeneity and reservoir complexity can affect field development plans and how active reservoir management and production optimization can add significant value to field understanding and value.
Drilling activity in Seram Island block is one of the most active in the Eastern Region of Indonesia. Drilling operator in the block has conducted drilling of 2 (two) exploration wells, where one of the well reached total depth to 19,230 ft. The well is one of the deepest onshore well in Indonesia. Both exploration wells have target to penetrate Manusela Formation as objective reservoir.
Actual drilling depth of the first exploration well LFN-1 in LFN field is 14,525 ft and the second well LFN-2 is 19,230 ft. The drilling effort in the LFN field faced many challenges, such as those experienced in LFN-1 well during drilling 8-1/2" hole section in Lower Nief formation whose lithology is limestone, partial loss occurred and in the consecutive formation of Kola with Shale whose lithology contained overpressure zone resulting in kick and well control effort has to be taken. This shows that the drilling operation in 8-1/2" hole section there is a narrow window of pressure regime between Pore Pressure (PP) and Fracture Pressure (FP) which is estimated to be ± 2 ppg. Thus drilling operator is required to use the latest method or technology to overcome the challenges and to finish drilling safely.
Efforts that were made to minimize operation problems in well LFN-1 have been analyzed and learned to be improvement on well LFN-2. One of the solutions selected was to use current well-known technology which is Manage Pressure Drilling (MPD) method on well LFN-2. The MPD is to be utilized on 8-1/2" hole section. The purpose of the application of the MPD method is to keep the Bottom Hole Pressure (BHP) to be constant in between Pore Pressure (PP) and Fracture Pressure (FP) thus minimizing the occurrence of losses and kick at the same time. The advantages of MPD usage are that we can make BHP constant during pipe connection so the hole does not allow kick and at the time of drilling, as it passes through the overpressure zone which is up to 17 ppg, the influx can be detected and anticipated quickly.
With the application of MPD method on LFN-2 well in 8-1/2" hole section, LFN-2 well could go according to plan and there was no problem as experienced before in well LFN-1. This is a good achievement in improving the performance of drilling at exploration wells with depth up to 19,230 ft.
Sarma, Dilip Kumar (Oil and Natural Gas Corporation Ltd.) | Pal, Tej (Oil and Natural Gas Corporation Ltd.) | Kumar, Dileep (Oil and Natural Gas Corporation Ltd.) | Lahiri, Gopal (Oil and Natural Gas Corporation Ltd.) | Manchalwar, V V (Oil and Natural Gas Corporation Ltd.)
Mumbai Offshore fields are consisting of heterogeneous limestone reservoirs. Some of the reservoirs consist of tight carbonate with poor wellbore transmissibility. With the maturity of the fields, improving production from tight reservoirs has become the main focus for sustaining overall production. However, the responses of conventional stimulation techniques such as matrix acidization with self-diverting acid, deep penetrated acid, conventional acid fracturing etc. are not very encouraging in a tight reservoir, which calls for novel stimulation approach.
To address the issues, reservoir properties, well completion strategies and previous stimulation practices were analyzed in collaborative approach. Based on analysis, a different stimulation approach Closed Fracture Acidizing (CFA) was identified as the potential technique. Closed Fracture Acidizing reopens previously created fracture system with a pre pad fluid pumped at high rates. It involves creating fractures with a viscous fluid, letting it close followed by pumping a suitable acid system at matrix rate for etching the fractures. To improve treatment efficiency vis-à-vis better etched conductivity, different techniques such as leak-off control additives, effective diversion system, viscous acid systems etc. are applied.
For application of the technique, some low producing wells completed in Mukta pay of Heera field, A1 and L1 layers of Mumbai High field and Panvel pay of B-192 field were identified. The well specific treatments were designed by using Cross-linked Guar gel for creating fractures and a customized foamed acid system for etching of fracture faces. Foamed acid has been selected in these treatments for better exposure of acids in the entire fracture network and effective flow back of the treatment fluids. The foamed acid was customized by using a viscoelastic surfactant (VES) as foaming as well as viscosifying agent. Converting the acid system to stable foam greatly controlled fluid leak-off, increased the effective fluid volume and retarded the reaction rate, which is desirable in carbonate reservoirs. The various additives such as cross-linker, breaker etc. were optimized at onboard laboratory in the well stimulation vessel.
The jobs have been implemented in ten wells under constant monitoring of treatment parameters during fracturing, closure and acidization. Post CFA jobs indicate 670 bbl/day of oil production from a non-flowing well and significant improvement of productivity in other wells.
This paper describes the details of Closed Fracture Acidizing technique, treatment design, lessons learned during execution and results. The novelty of the approach over the conventional stimulation techniques in tight carbonate reservoirs are the treatment methodology and use of foamed acid system for better acid etched fracture conductivity.