Pioneering Secondary Recovery Strategies in a Complex Geological Environment and Challenging Reservoirs Located in Offshore Sarawak

2021 ◽  
Author(s):  
Alister Albert Suggust ◽  
Aizuddin Khalid ◽  
Mohammad Zulfiqar Usop ◽  
M Idraki M Khalil
Keyword(s):  
Cost Benefit ◽  
Feasibility Studies ◽  
Production Performance ◽  
Oil Fields ◽  
Regional Study ◽  
Recovery Method ◽  
Secondary Recovery ◽  
Reservoir Compartmentalization ◽  
Ongoing Surveillance ◽  
Clastic Reservoirs

Abstract The Balingian province is located offshore Sarawak, comprising of at least 7 oil fields with its regional geology consisting of a combination of deltaic & shoreface system. Though consisting of clastic reservoirs, the fields are highly sophisticated in terms of reservoir compartmentalization, hence uncertainties in fluid contacts, differing depletion strategies and varying production performance per well. As the regional production has gone into brownfield stage, the challenge is to determine the most suitable secondary recovery method to prolong field life. The subsurface & feasibility studies conducted produced mixed results between application of water & gas injection, giving recovery factors between 30 to 40%, and implementation so much depending on source of water & gas and cost benefit analyses. The application of IOR across Balingian province are executed in pilot mode across all fields. While the pilots are still continuing, this paper is to share the methodology, recovery factors and process of the regional study and some results from the ongoing surveillance post-execution, and the wayforward.

Waterflooding in Carbonate Reservoirs: Does the Salinity Matter?

2014 ◽  
Vol 17 (03) ◽  
pp. 304-313 ◽  
Author(s):  
A.M.. M. Shehata ◽  
M.B.. B. Alotaibi ◽  
H.A.. A. Nasr-El-Din
Keyword(s):  
Oil Recovery ◽  
Sudden Change ◽  
Oil Production ◽  
Deionized Water ◽  
Production Performance ◽  
Shallow Aquifer ◽  
Secondary Recovery ◽  
Tertiary Recovery ◽  
The Impact ◽  
Indiana Limestone

Summary Waterflooding has been used for decades as a secondary oil-recovery mode to support oil-reservoir pressure and to drive oil into producing wells. Recently, the tuning of the salinity of the injected water in sandstone reservoirs was used to enhance oil recovery at different injection modes. Several possible low-salinity-waterflooding mechanisms in sandstone formations were studied. Also, modified seawater was tested in chalk reservoirs as a tertiary recovery mode and consequently reduced the residual oil saturation (ROS). In carbonate formations, the effect of the ionic strength of the injected brine on oil recovery has remained questionable. In this paper, coreflood studies were conducted on Indiana limestone rock samples at 195°F. The main objective of this study was to investigate the impact of the salinity of the injected brine on the oil recovery during secondary and tertiary recovery modes. Various brines were tested including deionized water, shallow-aquifer water, seawater, and as diluted seawater. Also, ions (Na+, Ca2+, Mg2+, and SO42−) were particularly excluded from seawater to determine their individual impact on fluid/rock interactions and hence on oil recovery. Oil recovery, pressure drop across the core, and core-effluent samples were analyzed for each coreflood experiment. The oil recovery using seawater, as in the secondary recovery mode, was, on the average, 50% of original oil in place (OOIP). A sudden change in the salinity of the injected brine from seawater in the secondary recovery mode to deionized water in the tertiary mode or vice versa had a significant effect on the oil-production performance. A solution of 20% diluted seawater did not reduce the ROS in the tertiary recovery mode after the injection of seawater as a secondary recovery mode for the Indiana limestone reservoir. On the other hand, 50% diluted seawater showed a slight change in the oil production after the injection of seawater and deionized water slugs. The Ca2+, Mg2+, and SO42− ions play a key role in oil mobilization in limestone rocks. Changing the ion composition of the injected brine between the different slugs of secondary and tertiary recovery modes showed a measurable increase in the oil production.

Estimation of the reliability of determination of filtering parameters of productive formations using multi-dimensional regression analysis

2021 ◽  
pp. 50-59
Author(s):  
D.A. Martyushev ◽  
◽  
I.N. Ponomareva ◽  
V.I. Galkin ◽  
Keyword(s):  
Regression Analysis ◽  
Multivariate Regression Analysis ◽  
Oil Fields ◽  
Technological Parameters ◽  
Recovery Method ◽  
Statistical Estimates ◽  
Production Analysis ◽  
Perm Krai ◽  
Pressure Stabilization

Determination of reliable values of filtration parameters of productive strata is the most important task of monitoring the processes of developing reserves. One of the most effective methods for solving the problem is hydrodynamic testing of wells using the pressure recovery method, as well as modern methods - the pressure stabilization method and the method based on production analysis (Decline Analyze). This article is devoted to the assessment of the reliability of these three methods in determining the filtration parameters of terrigenous and carbonate productive deposits of oil fields in the Perm Krai. To solve the problem, multivariate regression analysis was used. A series of multidimensional mathematical models of well flow rates was built using filtration parameters determined for each of the methods. It is proposed to consider the filtration parameters included in the models with the maximum statistical estimates of performance as the most reliable. With regard to the fields under consideration, it was found that in terrigenous reservoirs, all three methods demonstrate stable results. In carbonate reservoirs, reliable values of filtration parameters are determined by processing pressure build-up curves. Pressure stabilization and production analysis methods show less robust results and require additional research in order to develop sound recommendations for their practical application. Keywords: permeability; skin factor; pressure stabilization curve; decline analyze; liquid flow rate; geological and technological parameters; oil deposit; carbonate deposits.

SUB-SURFACE UNCERTAINTY IN OIL FIELDS: LEARNINGS FROM EARLY PRODUCTION OF LEGENDRE OIL FIELDS

2003 ◽  
Vol 43 (1) ◽  
pp. 401
Author(s):  
R. Seggie ◽  
F. Jamal ◽  
A. Jones ◽  
M. Lennane ◽  
G. McFadzean ◽  
...  
Keyword(s):  
Planning Process ◽  
Development Planning ◽  
Oil Field ◽  
Production Performance ◽  
Oil Fields ◽  
High Rate ◽  
Secondary Development ◽  
North West ◽  
Field Development ◽  
Small Primary

The Legendre North and South Oil Fields (together referred to as the field) have been producing since May 2001 from high rate horizontal wells and had produced 18 MMBBL by end 2002. This represents about 45% of the proven and probable reserves for the field.Many pre-drill uncertainties remain. The exploration and development wells are located primarily along the crest of the structure, leaving significant gross rock volume uncertainty on the flanks of the field. Qualitative use of amplitudes provides some insight into the Legendre North Field but not the Legendre South Field where the imaging is poor. The development wells were drilled horizontally and did not intersect any fluid contacts.Early field life has brought some surprises, despite a rigorous assessment of uncertainty during the field development planning process. Higher than expected gas-oil ratios suggested a saturated oil with small primary gas caps, rather than the predicted under-saturated oil. Due to the larger than expected gas volumes, the gas reinjection system proved to have inadequate redundancy resulting in constrained production from the field. The pre-drill geological model has required significant changes to reflect the drilling and production results to date. The intra-field shales needed to be areally much smaller than predicted to explain well intersections and production performance. This is consistent with outcrop analogues.Surprises are common when an oil field is first developed and often continue to arise during secondary development phases. Learnings, in the context of subsurface uncertainty, from other oil fields in the greater North West Shelf are compared briefly to highlight the importance of managing uncertainty during field development planning. It is important to have design flexibility to enable facility adjustments to be made easily, early in field life.

scholarly journals Cost–Benefit Analysis of Solar Thermal Plants with Storage in a Hydrothermal System

Energies ◽  
2021 ◽  
Vol 14 (18) ◽  
pp. 5662
Author(s):  
Cibelle Pereira Trama ◽  
Amaro Olímpio Pereira Júnior ◽  
Ana Paula Cardoso Guimarães ◽  
André Luiz Diniz ◽  
Leonardo dos Santos Reis Vieira
Keyword(s):  
Hydrothermal System ◽  
Cost Benefit Analysis ◽  
Cost Benefit ◽  
Feasibility Studies ◽  
Economic Benefits ◽  
Economic Feasibility ◽  
Levelized Cost Of Electricity ◽  
Cost Of Electricity ◽  
Thermoelectric Systems ◽  
The Cost

Economic feasibility studies of concentrated solar power (CSP) plants with thermal energy storage (TES) systems have been mainly based on the levelized cost of electricity (LCOE), disregarding the economic benefits to the electricity system resulting from the dispatchability of the CSP plants. The analysis of these benefits is essential since the existence of storage can provide greater operating flexibility to the system. Although there are few studies on the benefits of CSP plants in thermoelectric systems, this analysis has not yet been done in a predominantly hydroelectric system. In this paper, CSP plants with TES systems were inserted in a hydrothermal system in order to estimate the economic benefits and the net cost of electricity generated by those plants. The System Advisor Model (SAM) and the hydrothermal scheduling model DESSEM were used in a real case study of inclusion of CSP plants in the Brazilian system. The results indicate that the cost of a CSP plant, previously estimated by the LCOE, can be reduced by at least 37% when considering its benefits to a hydrothermal system, increasing its competitiveness with other technologies. Therefore, we propose the use of the net cost for an appropriate comparison among energy sources.

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