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.
Long range energy forecasts suggest that world demand for LNG would double by 2020. While much of this demand will be met by baseload LNG liquefaction plants, this growth trend is also leading to the evolution of new LNG market structures. This is evidenced by the emergence of mid-markets, principally regional markets which rely on smaller parcels of LNG than applicable to baseload plants, and exploit the opportunities offered by spot trades.
While onshore baseload projects (requiring long term Sale and Purchase Agreements) continue to be aggressively pursued, the emergence of mid-markets has generated interest in the monetisation of medium to smaller gas reserves. For offshore gas fields, the deployment of floating liquefaction units (LNG FPSOs) offers an interesting pathway to these emerging mid-markets.
A significant portion of the potentially exploitable gas reserves today is stranded gas. The pressure to bring these stranded reserves (estimated to be in the region of 4000 TCF) to the market is compelling. The LNG FPSO provides an attractive route to connecting smaller and medium size reserves to the emerging mid-markets. However, the initial deployment of LNG FPSOs is not without its challenges.
The paper overviews industry efforts at maturing LNG FPSO technologies to market ready status. It assesses the progress made on technology qualification for LNG liquefaction, LNG/LPG product containment and offloading systems. The need for functionality and reliability of these systems in the metocean environment (benign to severe) in the prospective development provinces has driven a sustained program of technology qualification by the proponents of the technology. The paper reports on the claims of these technology proprietors, and the industry's views of these claims.
The paper critically examines the concept and system critical issues relevant to LNG FPSO deployment, evaluates the principal technology and deployment risks, and explores avenues for the mitigation of these risks.
Concluding the above analysis, the paper assesses the potential of LNG-FPSOs to supply and stimulate the development of the mid-markets, and focuses, by way of example, on a notional opportunity in the Asia Pacific region.
Deepwater discovery development activities can be located in remote locations far from existing infrastructure like other facilities and pipelines. Major deepwater developments typically consist of subsea wells tied back to floating surface production facilities such as semisubmersibles, SPARs, TLPs, or FPSOs. The choice of production and export options for liquid hydrocarbons and gas is important and is affected by the distance to other infrastructure, the waterdepths involved, geohazards, reservoir fluid characteristics, production rates, and reserves. Another important factor is whether adjacent undeveloped discoveries exist to potentially share facilities and export options. Conventional production and export options involve oil and gas production facilities and pipelines with shipping pumps or compression as required to reach the closest transmission pipelines or onshore markets. In SE Asia, deepwater developments are often located in remote locations hundreds of kilometers from markets onshore, so the development production and export options must be wider in order to obtain economic and timely choices. In addition to pipeline options, liquid hydrocarbons can be stored offshore in the floating production facility or in an adjacent FSO, then offloaded and shuttled to markets by tankers. Gas production and export options can include long distance gas pipelines, Compressed Natural Gas (CNG) vessels, purity product (butane and propane) liquefied petroleum gas (LPG) FPSOs, methanol/DME FPSOs, and floating LNG FPSOs. This paper will show some of the technical concepts, risks, costs, and economics involved in making these choices.
As of today, no well is drilled without problem. Oil and gas companies spend about $ 25 billion annually on drilling. Unfortunately, not all of that money is well spent. A significant portion, about 20% is attributed to losses. These include loss of materials & drilling process continuity. In particular, wellbore stability related problem remedy cost is substanting and such problem are repeatedly occurring but still so complex that they are not easily solved. The necessary experience obtained by individuals or by the organization is difficult to transfer efficiently to those that need it. The objectives of this paper is to a problem analysis method called Case Base Reasoning( CBR) and its application in terms of a new level of active computerized support for information handling, decision support for wellbore instability cases and prediction of potential unwanted events in the drilling engineering domain.
CBR is well suited for dealing with the complexity of wellbore stability problems, and the large number of parameters involved, experience is stored in cases which are linked to a model of general domain knowledge. The general domain knowledge is containing information with explanatory support to case knowledge. A knowledge Tool named "Creek?? (research version) has been used here to create the ontology framework.
This paper mostly addresses how to make a case from real case data, create symbolic entities including case retrieval methodology and finally diagnosis similar problem cases.The cases resented are all related to improving the drilling plan, in such a way that the problem can be planned away throughts the next drilling plan. The resulting outcome from pased cases acts as input for making better drilling plan to avoid similar problems in the future.
Key words: Wellbore stability, Cased Based Reasoning, Model Based Reasoning, Ontology's, Case structure and drilling efficiency.
Wellbore instability problems are pack off, stuck pipe, lost circulation, poorhole cleaning and down hole equipment failure. These unwanted events are repeatedly occurring but still so complex that they are not easily solved. In our daily drilling operation, most practical problems need to be solved fast. Since most practical problems have occurred before, the solution to the problem is hidden in past experience, experience which either is identical or just similar to the new problem. Such problems can be solved efficiently by storing and then reusing similar experience, i.e. CBR. A similar, previous experience is a good initial approach to solving the problem.
There are a growing number of applications within the CBR market. In a recent book on methodology for building CBR applications (Bergmann-99), the authors present several examples of running applications. The most convincing CBR systems appear to be in the help-desk areas, particularly for trouble shooting in conjunction with complex equipment. The majority of current CBR researches are aiming at support during the manufacturing and planning phase (e.g. training, design information) rather than being directly integrated into the manufacturing process. Althoff (1998) present CBR as a means of managing the knowledge in the organizations. However, our work is more oriented towards software engineering best practice in business processes finally.
Wibisono, Kunto R. (ConocoPhillips Indonesia Inc.) | Burton, Robert C. (ConocoPhillips) | Hodge, Richard M. (ConocoPhillips) | Cassidy, Juanita M. (Halliburton Energy Services Group) | Wijaya, Rio (PT Halliburton Indonesia) | Nieuwland, Bastiaan (Halliburton Energy Services Group)
ConocoPhillips Indonesia Inc. Ltd. is producing oil and gas in various locations in Indonesia, both on and offshore. This paper covers work performed in the Belanak field offshore Indonesia. The field is located in Natuna Sea, north of Indonesia, near the border between Indonesia and Malaysia. The gas produced by the Belanak field is transported to Singapore and Malaysia.
Belanak wells which are drilled in the Gabus Massive reservoir have a bottom hole static temperature of 315ºF (157ºC). The wells are typically long horizontals (2,300 - 3,400 ft) with openhole completions utilizing stand-alone screens through the producing interval. The reservoir section is drilled with a water-based Drill-in-Fluid (DIF) consisting of polymer and CaCO3 particles and displaced to a solids-free, DIF prior to running the screens.
Typically, acid is used to degrade water-based DIF filtercake and remove CaCO3 contained in the filtercake. The use of a common acid was not an option for this development because of the high reservoir temperature (>300ºF). The combination of high reservoir temperature and long shut-in times after acid treatment lead to a high probability of severe corrosion of the sand control screens. In addition to the corrosion concerns with common acids, the rapid removal of the filtercake with acid could create localized, high leak-off of the treating fluid resulting in an uneven distribution of acid across the horizontal open-hole section.
To overcome these problems, a slow reacting alternative chemical solution was required allowing the stimulation fluid to be placed across the entire horizontal open-hole section before the CaCO3 filter cake was dissolved and before major losses started to occur. The solution was found in the application of a Chelant Based Acid System.
This paper details the application of the Chelant Based Acid System as a means to remove CaCO3 filter cakes in 10 Belanak wells, post treatment well performance, best practices, and lessons learned.
The Belanak field is located offshore in the Indonesian waters of the West Natuna Sea, near the border between Indonesia and Malaysia (see Figure 1). The field is produced from two wellhead platforms with a total of 35 development wells which were drilled and completed over a 2-year period between 2003 and 2005. Hydrocarbons are produced from five different reservoir intervals: Arang, Gabus Massive, Gabus Zone-3, Lower Gabus and SB-90. The focus of this paper is on well completion and openhole cleanup work performed on a series of Gabus Massive horizontal wells.
The Gabus Massive reservoir is comprised of a fairly homogeneous clear to white sandstone, generally medium to coarse grained although occasionally being fine grained. The sand is moderately well cemented, slightly calcareous and contains minor amounts of mica, kaolin and carbonaceous material9. The average reservoir data of the Gabus massive reservoir can be found in Table 1. Core porosity measurements show this sandstone to have good intergranular porosity. Porosity values range from 12% to 22%, with an average of 17%. The Gabus Massive has a high net-to-gross ratio and is easily correlated from well to well, indicating good reservoir continuity over the Belanak field. The thin interbedded shales found within the interval form only local or areally limited barriers to reservoir communication and the entire sand package is considered to be in fluid and pressure communication. This conclusion is also supported by pressure tests performed in exploration and appraisal wells drilled in the field. The Gabus Massive reservoir has a reservoir static temperature of 315ºF (157ºC) and an initial pressure of 3,400 psia at datum.
In the Belank field, reservoir temperatures average 315 F and reservoir sections are 3,500 to 4,500 ft drilled horizontally. A low-solids, brine-based reservoir drilling fluid was required because the wells use premium screens for sand control. Six wells were drilled with the sodium formate-based reservoir-drilling and completion fluids. Introduction The Belanak field is an oil-producing field off the coast of Indonesia. Reservoir temperatures average approximately 315 F. Six horizontal-well completions were planned from the Belanak A platform.
Bradshaw, Roger J. (ConocoPhillips) | Hodge, Richard M. (ConocoPhillips) | Wolf, Nick O. (ConocoPhillips) | Knox, David Alexander (M-I SWACO) | Hudson, Charles Edwin (M-I SWACO) | Evans, Eddie (M-I SWACO)
Copyright 2006, Society of Petroleum Engineers This paper was prepared for presentation at the 2006 SPE International Symposium and Exhibition on Formation Damage Control held in Lafayette, L.A., 15-17 February 2006. This paper was selected for presentation by an SPE Program Committee following review of information contained in a proposal submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to a proposal of not more than 300 words; illustrations may not be copied. The proposal must contain conspicuous acknowledgment of where and by whom the paper was presented.
The use of low-solids, water-based reservoir drilling fluids has generally been restricted to fields with temperatures of less than 300°F, primarily due to the limitations of fluids in more aggressive environments. The Miano and Sawan fields in Pakistan are both classified as high temperature (up to 340°F BHST), and some wells have been recognised as requiring sand control for optimal production. The operator of this field is dedicated to the application of water-based muds in all activities to reduce the environmental impact of operations.
Based on these criteria and extensive laboratory testing for thermal stability and expandable screen (filter cake quality) compatibility, a formate-based, low-solids, reservoir drilling fluid was selected. The laboratory performance of the fluid will be confirmed by the performance in the world's first field application of high-temperature formate drilling fluid run with expandable screens.
This reference is for an abstract only. A full paper was not submittedfor this conference.
The Belanak FPSO was installed in the Belanak Field in October 2004 andshould reach full production in the 3rd quarter of 2005. It will form thecentral production hub for a number of fields in Indonesiaâ€™s West Natuna Seaarea, including Belanak, Belut, Kerisi and Tawes. ConocoPhillips is theoperator for Block B with Inpex and ChevronTexaco as equity partners. Belanakhas the capability to process and export 350mmscfd of sales quality gas, up to100,000 bpd of stabilized crude and 23,000 bpd of LPG in separate propane andbutane streams.
Flowlines from two 24 slot wellhead platforms transport raw well fluids tothe FPSO, where they are processed and exported as crude via a loading buoy,gas via pipelines to Malaysia and Singapore or as LPG to a separate storagetanker to be moored in the Belanak Field. The Belanak facilities are designedfor a 30 year life and offer considerable flexibility to accommodate futurefields and deal with incoming hydrocarbon streams as well as deal with H2S,CO2, Mercury and Mercaptans.
The vessel was designed and built in Asia with project management and designbeing conducted in Singapore, the 285m hull was fabricated in China, and thetopsides were built and integrated in Indonesia. With approximately 25,000tonnes of topsides process equipment which includes LPG fractionation as wellas 1.2 million barrels of oil storage, Belanak is one of the most complex FPSOsbuilt by the industry to date.
This paper will further describe the Belanak FPSO and discuss some of thechallenges that the operator and its contractors faced in designing anddelivering this production facility on schedule and within budgetexpectations.