Widodo, Untung Hendy (ConocoPhillips Indonesia)
This paper aimed to evaluate the effectiveness of Apprenticeship Program implemented by ConocoPhillips Indonesia. The scope of this study is fresh graduate hires in the selection year 2010-2012. This study used a qualitative research methodology by developing strategies based on the Three Gears of Development developed by the Corporate Leadership Council (CLC) and the method refers to the Kirkpatrick's evaluation model. From the analysis performed it was concluded that the Apprenticeship Program has brought business impact, the most useful method of development is experiencing in which there are on the job training and project assignments embedded in meaningful assignment, as well as the relationship and feedback through coaching and mentoring.
The paper describes the reservoir management experiences of Kerisi field after seven years of production. Kerisi field is located in Block B of South Natuna Sea and comprises five separate reservoirs in three geological zones.
Forty seven percent of the reservoir hydrocarbons are located in the Upper Gabus Massive West (UGMW) reservoir; optimum production from this formation is expected to be reached by injecting gas at the gas cap. The source of injected gas is from all five Kerisi reservoirs and the nearby Hiu field. The liquid hydrocarbon production from UGMW and the production/injection of Kerisi – Hiu produced gas in this formation is of high importance to the future development stage of Kerisi – Hiu field.
The initial reservoir management strategy was to optimize oil value with injection while meeting gas sales requirements. Both gas sales commitments and injection targets were honored with high Kerisi – Hiu production and the strong performance from other gas fields.
With time, other gas fields became depleted faster than expected. Thus, it was decided to reduce gas injection rate in UGMW and produce more Kerisi and Hiu gas to increase gas sales volumes. The reduced of injection rates improved short term economic of the fields, but the effect to reservoir and long term economic benefit still needs evaluation.
This paper will (1) show the impact of varying injection rate at UGMW to the overall Kerisi – Hiu field future production, include oil, gas, condensate, and LPG, (2) discuss an updated – improved reservoir management strategy, and (3) present an economic evaluation of the updated reservoir management strategy for the Kerisi – Hiu fields.
The purpose of the paper is to share lessons learned in the evaluation of historical performance, data acquisition and monitoring, static and dynamic modeling, history matching, prediction of future performance, and the dynamics of reservoir management strategy which support future profitable opportunities.
Production and transportation of high paraffinic crudes in offshore fields is a major flow assurance challenge for the oil and gas industry. The challenge is particularly great when the sea water temperature is lower than the pour point of the crude being transported. This paper describes flow assurance issues that have been addressed for handling subsea transportation of paraffinic crudes in Indonesia. Pour point depressant (PPD) has been continuously injected into the oil production manifold handling high pour point crude to cause the formation of a sufficiently weak gel in the subsea pipeline to enable restart after a long shut-in. Currently, production of a condensate has started that blends with the waxy crude. The PPT (pour point temperature) and live gel strength of the condensate and crude oil blends are significantly lowered and require less or no PPD injection. Since the PPD injection involves significant operating costs, this paper describes the joint effort by operations and technology staffs to develop a reliable method to optimize the PPD treating rate on a daily basis. PPTs and live gel strength were measured in the in-house laboratory using a densitometer (identical to the one used at the field lab) and a rheometer respectively. An equation was generated by fitting a smooth curve to correlate PPT with live gel strength. This equation provides a convenient method to estimate live gel strength based on onsite PPT measurements. Considering that the crude oil and condensate blend are changing over time, routine monitoring of blend PPT using a reliable and simple onsite method and estimating gel strength based on PPT results, enable identification of the optimum PPD dosage by the operations staff to ensure flow assurance and minimize treating costs in a timely fashion.
This paper applies a single well numerical model using a reservoir simulator and accommodating geological data such as depth structure, gross and net thickness, and distribution of petrophysical properties to interpret a DST data. History matching pressures and rates of the DST data is conducted after incorporating the geological, reservoir engineering, and production data.
In this single well simulation study, three DST data from well North Belut 3 are as the matching target used in the history matching using commercial numerical simulator with black oil formulation and three dimensional models. The PVT data is generated from an EOS model in which pseudoization is applied to reduce the components into 9. A one and a half foot model, or total of 1309 Z-grid dimension, is used to accommodate facies inconsistency and fluid gradient changes. Capillary pressures are obtained from mercury injection laboratory experiment of samples from four wells and are distributed according to permeability range values.On the other hand, the permeability curves are generated using the Corey function.
The interpretation through the history matching process is described in steps to show advantages of using this method. Correct PVT fluid type, absolute permeability, and skin factor are the most affected on the pressure and rate matching process. The steps could explain and improve the understanding of reservoir characterization. The results are also compared with the analytical interpretations, which study is already done before by other person, to see the reliability. A good agreement on the permeability value is gained, with a possiblility of different net to gross ration interpretation. The skin factors of the numerical method are reasonably positive values, and tend to much less than the analytical results. This suggests that the near well bore damage may not as bad as the analytical interpretation implied.
Among one of methods to understand the characteristic of reservoir is through welltest interpretation. Of which welltest type to be used, depends on the development stage of a reservoir.Drill Stem test is a welltest that usually runs on new wells. Interpretation of the Drill Stem Test (DST) results in permeability, near-wellbore formation condition or skin factor, fluids characteristic, and reservoir boundary. The interpretation of DST curve can be done using the available analytical solutions, or numerical solutions as what we do here in this paper.
For a complex problem such as multiphase flow of a condensate system, a numerical simulation is a great advantage as analytical solution doest take into account of the mass mass transfer between oil and gas phases during transient flow, but, it rather simplifies these chemical activities into a steady state process.To accommodate such a fluid system and its geological system, a black oil reservoir simulator is generated together with input of PVT laboratory and geology data.A history matching process was conducted after a complete modelling of reservoir in the simulator.The history matching will need a parameter adjustment such as permeability and skin factor value. The agreements of curve profiles between welltest result and simulation result, will do the validity of the model characterization. The quantitative parameter results such as skin, effective permeability, are then compared with the available analytical interpretation results. A reliable explanation of the differences between analytical solution and numerical sulitions is gained.
In October 2003, development drilling of the ConocoPhillips Indonesia Inc.Ltd operated Belanak Field commenced when the platform rig was rigged up over a previously installed twenty-four slot platform. Drilling commenced with the objective of drilling and completing ten slant directional wells and six horizontal wells.
The objective of the Field development was to have high production rates available when the FPSO facilities arrived approximately twelve months later. Since the wells had to be pre-drilled before first production,it made sense to utilize a full batch drilling concept in order to minimize costs.
The 13-3/8" surface casing strings were successfully batch set on all sixteen wells. This section was completed fifteen days ahead of budget time and set several world record penetration rates for a 16" tricone bits.
The 9-7/8" hole/7-5/8" casing sections were batch set in ten wells. Most well objectives were met and the performance was exceptional in some wells, but, this section was plagued by surface and downhole equipment failures.
The 12-1/4" hole/9-5/8" casing sections were batch set in six wells. All well objectives were met including landing all wells in the reservoir at 90o. Time to complete this section was longer than expected due to inconsistent BHA response.
The 8-1/2" horizontal hole sections were then drilled and completed with a 3,500 ft average hole length for the same six wells.
This paper will focus on the drilling operations and discuss the performance and problems encountered. The Belanak drilling team was committed to continuous improvement by capturing data and immediately implementing the learning's. This commitment to maximize the learning curve resulted in minimizing cost and a successful intensive batch drilling operation.
The Belanak field in the Natuna Sea of Indonesia is located 253 miles northeast of Singapore in 300' water depth (Figure 1). The field development consists of two wellhead platforms, with 16 wells drilled from platform A, and 18 wells planned for platform B. Due to the remote location of the development, and the space and storage limitations inherent to a platform rig, logistics and equipment design were the major front-end engineering issues of the drilling project. The early concerted effort of the operator and contractors to front-end planning and design led to the realization of several drilling records and first-time accomplishments in the Natuna Sea.
Figure 1: Area map of the Belanak field.
Supply Line Logistics
Since a platform rig would have very limited capacity for storing bulk and tubular materials, and the field was to be batch drilled, the supply line had to be shortened as more frequent shipments to the rig would be required. As a result, the jetty and wharf at Matak Island, located 53 miles from Belanak platforms A and B, were refurbished. Utilizing Matak as the shore base for the drilling and completion operations, instead of Batam Island located four miles from Singapore, shortened the supply line by approximately 200 miles. This reduced the transit time from 23 hours to just 5 hours one-way. This reduction made it easier to coordinate and expedite the mobilization of materials and equipment to the rig utilizing one platform supply vessel.
Construction of the Shore Base Facilities. The necessary refurbishment of the Matak wharf and jetty, and the associated construction of the facilities to support the Belanak drilling operation began in February 2003 with the initial mobilization of materials and equipment. In the ensuing months, the wharf was refurbished with a new steel-reinforced concrete foundation to support storage, crane activities, a liquid mud plant (LMP), and a bulk tank facility. Foundation specifications were critical as much of the area was reclaimed land and had limited load-bearing capability.
Upon completion of the foundation, construction of the LMP and the bulk tank facility commenced (Figure 2). The ability to mix and store mud, cement, and completion fluids at the shore base for transport to the rig was crucial. The LMP was designed for mixing pre-hydrated bentonite, unweighted non-aqueous based mud (NABM) pre-mix, and brine. The majority of the storage and mixing tanks were manufactured in the United States, and were constructed in either Singapore or Matak. The LMP consists of a 250-bbl mixing tank, two brine tanks with combined storage capacity of 4600 bbls, two NABM tanks for storing up to 2000 bbls, and one multipurpose tank for storing up to 1000 bbls. The bulk tank facility was designed for storing barite, bentonite, and cement, as well as for mixing neat cement with silica flour. The total storage capacity of the bulk tank facility is 12,000 cubic feet. Two sets of cutting bottles are utilized to transfer bulk barite in 3300-lb sacks, and bentonite and cement in 2200-lb sacks to their respective storage tanks. A third set of cutting bottles is utilized to blend 100-lb sacks of silica flour with neat cement for storage of the blended product. Construction of the LMP and bulk tank facility was completed in August 2003, which concluded the refurbishment and construction project at Matak six months after it began.
This work provides the development, validation, and appli-cation of new decline type curves for a well with a finite conductivity vertical fracture centered in a bounded, circular reservoir. This work fills a significant void in the modern inventory of decline type curves. In particular, this work is directly applicable to production data analysis for cases taken from low permeability gas reservoirs.
Using an appropriate analytical solution for this case, we pre-pared "decline" type curves for FcD values from 0.1 to 1000 - individual type curves are generated for each FcD value using a range of reD values from 2 to 1000. The following "type curves" are provided:
"Fetkovich" format rate-time decline type curves (con-stant pressure case): qDd versus tDd
"Fetkovich-McCray" format rate-time decline type curves (equivalent constant rate case): qDd versus
"Fetkovich-McCray" format rate-cumulative decline type curves: qDd versus NpDd
We provide an example demonstration of the methodology for decline type curve analysis using a field case of continuously measured production rate and surface pressure data obtained from a low permeability gas reservoir.
These solutions/type curves provide an analysis/interpretation mechanism that has not previously been available in the petroleum literature. Compared to field data, we find that the traditional type curve solutions for an infinite conductivity vertical fracture are typically inadequate - and, the new solutions for a well with a finite conductivity vertical fracture clearly show much more representative behavior. This validation suggests that the proposed type curves will have broad utility in the petroleum literature - particularly for applications in low permeability gas reservoirs.
The following objectives are proposed for this work:
To develop and validate a series of decline type curves for a well with a finite conductivity vertical fracture centered in a bounded, circular reservoir.
To provide a methodology for using decline type curves to analyze and interpret production or injection well performance for a well with a finite conductivity vertical fracture.
To demonstrate these new type curves using continuously measured production data (rates and pressures).
In considering these objectives we note that we are strongly motivated to provide these tools in light of the current high level of activity in the analysis and interpretation of reservoir performance data acquired from low permeability gas reservoirs. We recognize that current methods based on the case of a vertical well with an infinite conductivity vertical fracture are overly-ideal for low permeability reservoirs and we must reconcile the need for a new decline type curve for a finite conductivity vertical fracture. This rationale is the moti-vation for this work.