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PROCEEDINGS, INDONESIAN PETROLEUM ASSOCIATION
Twenty-Eighth Annual Convention & Exhibition, October 2001

RESERVOIR SIMULATION TO INCREASE RECOVERY IN KAJI SEMOGA FIELD

Ahmad Syaifudin*

ABSTRACT

The Kaji Semoga Field is located in Rimau PSC Area of PT. Exspan Nusantara (Figure 1). The field was discovered by the drilling of KS-1 well in 1996. The Kaji Semoga field consists of two oil pools separated by a structural saddle, namely Kaji pool with OWC at 2851 ft Sub Sea, and Semoga pool with OWC at 2629 ft Sub Sea. Each pool also has its gas oil contact (Figure 2). Currently, the daily production of Kaji Semoga field is 60,000 BOPD with negligible water cut and has 40 MMB cumulative oil production. Oil production is mostly from Baturaja Carbonate (90% of production) with a minor contribution from the Talang Akar Sand.

A reservoir simulation model was built as a tool to lead to an optimum field development, i.e. maximum recovery, and to predict the future field production performance. The Original Oil In Place (OOIP) is approximately 400 MMB and it is expected that a minimum of 40% recovery factor could be achieved with the right development scenario.

* P.T. Exspan Nusantara

PROCEEDINGS, INDONESIAN PETROLEUM ASSOCIATION
Twenty-Eighth Annual Convention & Exhibition, October 2001

A MOVABLE OFFSHORE GAS PRODUCTION UNIT FOR WEST NATUNA

Joao G. de Oliveira*
Yogi Prayogi*

ABSTRACT

The Hang Tuah Platform is a Movable Offshore Gas Production Unit in the West Natuna Sea Block B operated by Conoco Indonesia Inc. Ltd. (CIIL) on behalf of Pertamina. The name of the platform, Hang Tuah, refers to Indonesia’s legendary Melayu Ethnic Commander known for his adventurism and bravery. The Hang Tuah is an important element of the phased development of the Block B gas fields, and production from these fields is one of the sources of supply that feeds the West Natuna Transportation System (WNTS), i.e., the export pipeline system to Singapore.

This platform concept is similar to a production jack- up, but it is designed for a small number of field relocations. As such, it provides all the benefits of a bottom-founded structure with the ability to be relocated to other areas of the Natuna Sea anytime during its 25-year design life. The self-installing concept utilizes self-contained buoyancy for flotation and a temporary “on-hire” jacking system to lower the base foundation and elevate the deck.

After four months of concept studies, seven months of in-house preliminary engineering and twelve months of front-end design with Arup Energy in London, an EPCI contract was awarded to a consortium including PT Citra Panji Manunggal, Hyundai Heavy Industries Co. Ltd. and Hyundai Corporation (HHI) for the Hang Tuah in early 1999. The EPCI scope of work was to design build and install the complete Hang Tuah platform, including onshore and offshore hook up and commissioning services. Also included were some modifications to the existing Belida platforms, and all subsea work and well control system, but excluding drilling and trees.

The project execution offered many challenges and these were successfully addressed by the CIIL Project Management Team. In particular, the whole execution, from contract award to First Gas was conducted without a single lost workday case or safety incident.

* Conoco Indonesia Inc. Ltd.

PROCEEDINGS, INDONESIAN PETROLEUM ASSOCIATION
Twenty-Eighth Annual Convention & Exhibition, October 2001

IMPROVEMENT IN OIL RECOVERY BY WATER DRIVEN
MISCIBLE CO2 SLUG FLOODING

Dedy Kristanto*
Septoratno Siregar**

ABSTRACT

Oil displacement experiments with water driven miscible CO2 slug flooding were conducted using core flood apparatus. The objectives of the research were to determine the CO2 slug sizes which correspond to the maximum oil recovery if used for continuous CO2 displacement processes and to study the effect of CO2 slug size variation on oil recovery.

The reservoir core model used was a 43 cm length of 5.12 cm diameter cylindrical artificial core with 30% porosity and 1237 mD permeability. The displacement processes were done under a miscible condition for DS-01 oil sample at 2500 psi displacement pressure and 167 ⁰F temperature with 10%, 20%, 30% PV CO2 slug sizes driven by formation water and finally 100% PV or continuous CO2 flooding. The displacement was done horizontally at the rate of displacement in porous media of 3.24 cm/hour and injection continued up to 1.2 PV cumulative fluid injected.

Based on the experiment results, we observe that oil recovery at horizontal core displacement for the corresponding CO2 slug sizes are 75.12%, 82.28%, 84.68% and 87.10% of initial oil in place. The optimum CO2 slug size for DS-01 oil sample is 32% PV.

INTRODUCTION

CO2 injection has recently gained great interest in miscible flooding research efforts. CO2 gas has a low viscosity, similar to that of other hydrocarbon gases.

* U.P.N Veteran, Yogyakarta ** Institute Technology Bandung

PROCEEDINGS, INDONESIAN PETROLEUM ASSOCIATION
Thirtieth Annual Convention & Exhibition, August 2005

AN ANALYTICAL MODEL TO ALLOCATE LAYERED HISTORICAL PRODUCTION DATA TO ENHANCE RESERVOIR MANAGEMENT IN A MATURE WATERFLOOD: THE MINAS FIELD CASE

Alex Sulaksana*

ABSTRACT

Allocating production data among sand layers has always been a problem in managing a multi-layer asset with commingled production. Having a production profile by sand will enhance reservoir management. This study demonstrates that integrating petrophysical and production/completion data into an analytical model is an inexpensive and practical solution to obtain allocated production data by sand layer in Minas Field, Indonesia.

The Minas Field has been waterflooded since early 1970’s. As technology advancements were made in the area of integrating production and petrophysical data, the opportunity naturally lent itself to Minas. An analytical reservoir model was developed by combining the radial steady-state Darcy equation, material balance, fractional flow concept and Buckley-Leverett Frontal Advance Theory, adopting all associated assumptions. Reliable formation evaluation data are critical for the model. The model analytically simulates waterflooding conditions where reservoir pressure is kept relatively constant and assumes the oil relative permeability profile is responsible for declining oil production. A mechanical skin factor was calculated to represent partial-perforation effects using the Kuchuk-Kirwan formula. Buckley-Leverett was used to estimate post- breakthrough performance. The model runs through 50+ years of completion histories on over 1450 wells.

The technique helps to obtain more reliable estimates of production data allocated by sand and also the approximate value of historical average oil saturation by sand. The calculation results were verified by comparing with 36 observed Production Logging Tool (PLT) data. This method has been widely used in Minas and, when combined with diagnostic maps, played a key role in screening and identifying dozens of new candidates. The technique identified the best layers for water injection in the northern area of Minas, which subsequently resulted in a reserves increase of 2.5 MMBO.

We believe this technique offers improvements over conventional reservoir flow capacity, kh, techniques and wish to share it for review, comments and suggestions.

* P.T. Caltex Pacific Indonesia

PROCEEDINGS, INDONESIAN PETROLEUM ASSOCIATION
Thirtieth Annual Convention & Exhibition, August 2005

DESIGN AND IMPLEMENTATION OF CALIBRATION PLUG AS A KEY
TO SUCCESS OF TUBINGLESS COMPLETION IN TUNU FIELD

Sergio Giorgi*
Dominique Larrondo*
Christian Labeyrie*
Andre Glowacz*
Alain Bourgeois**

ABSTRACT

The use of tubingless completion operations in Tunu field has allowed Total E&P Indonésie to decrease the cost and time per well when compared with previous monobore type completions. Although this cost saving initiative is not new for the industry, in the particular case of Tunu field, a very important constraint had to be solved first.

One of the biggest constraints of the tubingless completion operations performed in Tunu field is how to avoid any under- or over-displacement while cementing the 4-1/2” completion tubing as the production casing. As an additional constraint, this must be achieved while keeping the so called “shoe track“ at an industry minimum value in order to avoid either drilling deeper into high pressure zones or leaving reserves without perforating as both choices could have important HSE and cost impacts. Solving these problems could lead to substantial costs savings and accelerated production.

To overcome these problems, TOTAL E&P Indonesie and the local company P.T. Saga Trade Murni co- developed a simple and low cost device, called “calibration plug”, that allows avoiding all the above mentioned constraints.

Several qualification tests had been performed on the calibration plug design in order to meet industry standards. These tests included erosion test, pressure and temperature test, compression strength test and rupture disk tests. The whole process starting from the design until the manufacturing of the calibration plug was performed in Balikpapan, Indonesia and is a good example of the “working together” philosophy that TOTAL E&P Indonesie is constantly promoting with its local contractors and community.

Since the introduction of the calibration plug in January 2003, more than 80 tubingless wells have already been completed with an impressive record of 100% achievement, confirming that the calibration plug device is also field proven and reliable.

This simple, innovative and very cheap device has allowed reducing the shoe track length to a very minimum (5 to 10 meters from an original length of 40m) while:

· Avoiding drilling additional meters with the risk of entering into high pressure zones

· Eliminating risks of leaving reserves that cannot be accessed ( behind the shoe track)

· Eliminating risks of potential remedial operations ( +/- 1 00KUSD per operation)

· Avoiding any volumetric discrepancy while displacing the cement slurry as the bump is mandatory to pressure test the tubing to its full working pressure

This paper will discuss and explain the design, factory acceptance test and working procedure in more detail.

* Total E&P Indonesie

** Total, Austral

PROCEEDINGS, INDONESIAN PETROLEUM ASSOCIATION
Thirtieth Annual Convention & Exhibition, August 2005

NINE INCH x 10,000 PSI WP DUAL CONDUCTOR SHARING WELLHEADS APPLICATION ON AN OFFSHORE GAS FIELD DEVELOPMENT

Jean-Baptiste Faget*
Jean-Christophe Monneyron*
Nicolas Payer*
Alain Bourgeois*
Liew Huey Cherng**

ABSTRACT

Splitter wellheads allow several wells to be drilled from the same conductor pipe, which can bring significant benefits for conventional offshore developments by reducing the size and/or number of wellhead platforms or by giving access to additional reserves from existing platform slots.

In April 2003, Cameron dual 9” CSW were successfully installed by Total E&P Indonésie on Peciko offshore gas field development as the first worldwide application of a 9” x 10,000 psi dual splitter wellhead and 4-1/2” x 6,500 psi Xmas-Tree.

Thanks to this technology, 120 million USD could be saved on surface facilities by reducing the number of wellhead platforms from 10 to 7 while targeting the same gas reserves. Drilling and completion costs remained in line with initial plans, as the savings made with the slimmed down well architectures were counterbalanced by the higher well departures induced by the reduced number of platforms.

To the end of 2004, 16 splitter wells (8 sets of dual CSW) have been drilled and completed without any major technical problem, 14 of them ahead of planning and below budget.

* Total E&P Indonesie

** Total, Cameron