EOR preliminary analysis is pivotal to be performed at early stage of assessment in order to elucidate EOR feasibility. This study proposes an in-depth analysis toolkit for EOR preliminary evaluation. The toolkit incorporates EOR screening, predictive, economic, risk analysis and optimisation modules. The screening module introduces algorithms which assimilates statistical and engineering notions into consideration. The United States Department of Energy (U.S. DOE) predictive models were implemented in the predictive module. The economic module is available to assess project attractiveness, while Monte Carlo Simulation is applied to quantify risk and uncertainty of the evaluated project. Optimization scenario of EOR practice can be evaluated using the optimisation module, in which stochastic methods of Genetic Algorithms (GA), Particle Swarm Optimization (PSO) and Evolutionary Strategy (ES) were applied in the algorithms. The modules were combined into an integrated package of EOR preliminary assessment. Finally, we utilised the toolkit to evaluate several Indonesian oil fields for EOR evaluation (past projects) and feasibility (future projects). The attempt was able to update the previous consideration regarding EOR attractiveness and open new opportunity for EOR implementation in Indonesia.
Pertamina Hulu Energi operates numerous wells that produce gas from unconsolidated, tight sands in the Mahakam Delta. The company maintains a zero-sand production policy as its surface facilities are not designed to handle sand. If sand is produced, the wells are choked back, thus impairing the overall field production. To fix sand and fines in place, the primary sand control method used has been multizone single-trip gravel packing, sometimes in conjunction with sand consolidation or ceramic screen for noneconomic zones. However, the current state of the Tunu shallow portfolio renders sand consolidation infeasible, as more than 50% of the remaining reservoirs are either low-stakes (i.e. not economical) or are located in low-permeability zones. Against this backdrop, sand conglomeration is being considered as an alternative solution to produce the remaining reservoirs. A trial has been conducted to assess the feasibility of using sand conglomeration technology as an alternative to sand consolidation in the Mahakam Delta, the results of which will be reviewed in this paper.
Handil is a mature oil and gas field with dozens of wells drilled within 70-m distance. It has been developed since 1975 and operated by Indonesian national oil company, PT Pertamina Hulu Mahakam. Handil shallow reservoirs are located at depths between 200 and 1500 m true vertical depth (TVD). It has strong aquifer support and unconsolidated permeable sandstone reservoirs with poorly sorted grain size, requiring gravel pack completion. Since 2005, there have been 39 wells completed with gravel pack, contributing 40% of total Handil field production. Handil gravel pack wells are facing productivity impairment; several production tests indicated that 30% of the completed zones have a very low productivity index (less than 0.5 STB/D/psi) after a few years of production. Organic clay acid (OCA) was proposed as a matrix acidizing technology to dissolve the fines in the critical near-wellbore matrix. For many years, matrix acidizing has been used to remove formation damage or improve productivity in formations containing siliceous clay. The most commonly used treatment fluid is mud acid, which is a mixture of hydrofluoric acid (HF) and hydrochloric acid (HCl). In many conventional mud acid treatments, after an initially good response to the treatment, the production falls to levels similar to those before the treatment; this is thought to be due to the precipitation from the reaction of HF with silica material on feldspar/clay, which results in more hydrated silica gel. Unlike conventional mud acid, OCA can allow a deeper live-acid penetration into the formation and limit possible reaction-product precipitates, which will enhance the effectiveness of the stimulation treatments. Two OCA trial treatments were executed through coiled tubing. In the first job, the chemicals created an emulsion that was not compatible with fluid on the surface facilities. Demulsifier treatment on the surface successfully diluted the emulsion. Some adjustments on chemical composition have been applied on the second job, which successfully removed the emulsion. The pilot test yielded total oil production up to 900 BOPD (4,000 BLPD) instantaneous gain with ~80% improvement on productivity by reducing skin from >100 to 5. Currently, both wells are still flowing after 6 months of production. Following this success story, more than 11 OCA jobs are planned to improve the productivity of the existing zones in 2018. A recent matrix acidizing campaign in Handil shallow wells, highlighting the damage verification, candidate selection, acid chemistry, operational constraints, production results, and future opportunities. The logistics which include the flowback of spent acids and acid neutralization in the swamp area, and the addition of demulsifier in surface facilities will also be discussed. There were no core samples available to run a formation response test to the acid prior to the matrix acidizing treatment.
This article performs a valuation analysis of LLP Compression in project investment plan at Tango Field in Mehacca Block. The LLP Compression investment project plan is currently under consideration for a Final Investment Decision (FID). The analysis is conducted by using quantitative methodology approach to evaluate 2 project scenario based on its cash flow. The outcome of financial valuation could assist decision maker in the company, in determining whether the project is economically profitable, whether it should be executed, what scenario can generate maximum economic profit for the company, and also what financial factor affecting LLP Compression Project cash flow that should be managed to avoid negative financial results and to forecast project likelihood of success. For DCF analysis, with company discount rate at 10.2%, the Net Present Value (NPV) result is 1.12 Million USD for Scenario 1 and 0.91 Million USD for Scenario 2. Internal Rate of Return (IRR) for both scenarios are higher than company’s discount rate. Payback Period for both scenarios are also the same in year 2026, or 2 years after production. Profitability Index (PI) for Scenario 1 is slightly higher than Scenario 1 amounting at 1.07, while PI for scenario 2 is 1.03. All of the parameters from DCF gives positive result more than expected return, with scenario 1 that provide better value than scenario 2. Monte Carlo simulation is also used to provide a likelihood of having a negative NPV. The result is that both scenarios have probability negative NPV amounting 28% for scenario 1 and 30% for scenario 2. Based on Monte Carlo Simulation result, scenario 1 has slightly lower probability of generating negative NPV than Scenario 2. Sensitivity analysis is also being used to look how large NPV project varies if the parameter inputs are changed. Four parameters tested with assumption change at ± 25% from original condition. Based on sensitivity analysis, it is observed that Gas Production, Gas Price are the most sensitive parameter for both scenarios of LLP Compression project. In summary, the LLP Compression Project investment plan is feasible to be executed for both scenarios, with scenario 1 provides higher economic profit than scenario 2, and it also generates slightly lower probability negative NPV than scenario 2. Since LLP Compression Project has probability of gaining negative NPV based on Monte Carlo Simulation Result, hence several strategies to minimize project risk exposure are required to be determined before project execution.
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