This course discusses the fundamental sand control considerations involved in completing a well and introduces the various sand control techniques commonly used across the industry, including standalone screens, gravel packs, high rate water packs and frac-packs. It requires only a basic understanding of oilfield operations and is intended for drilling, completion and production personnel with some sand control experience who are looking to gain a better understanding of each technique’s advantages, limitations and application window for use in their upcoming completions.
The Sanga-Sanga PSC fields are located onshore Mahakam delta, East Kalimantan, Indonesia. Since the 1970s, they have produced over 80% of originally estimated gas in place with the remaining gas locked up in low permeability sands. A prize of at least 0.75 Tcf would be achievable, if these sub milli-Darcy resources could be developed. However, previous attempts at hydraulic fracturing, over three decades, have been spectacularly ineffective and rarely enjoyed any improvement or uplift at all.
During late 2006, a detailed review of the regional stress-state and prior unsuccessful frac operations was performed. This review unearthed significant evidence of a reverse stress-ordering in the deep low permeability sands, resulting in horizontal fractures being created. While this provided some logic behind the widespread failure rate, it did not in itself offer a direct solution. However, there was also sufficient evidence from previous frac history, to indicate that the solution may lie with a pore-pressure reduction. A pilot program, with meticulous candidate selection was planned to investigate this.
Further investigation determined the presence of a strong poro-elastic relationship and it was assessed that when combined with longevity of production (30 years), that the stress-state would be substantially affected. During 2008, a suite of well candidates were carefully selected with a range of reduced pore- pressures, aligned with the poro-elastic understanding, hydraulic frac treatments were performed and the wells flowed and produced for two years to confirm productivity. The subsequent production behaviour, confirmed a very positive response and the treated wells netted substantial gas/condensate sales. Production behaviour confirmed the poro-elastic relationships and a set of absolute guidelines on candidate selection and fracture execution were created. Subsequent operations that have adhered to these strict guidelines have been extremely successful. The ability of the new approach to reverse a 30- year trend of hydraulic fracturing failure will now lead to the development of the remaining resource within the fields. An extensive treatment campaign will now be possible to perform with between 50 - 100 candidates well opportunities likely to be available in the field.
A careful assessment of the regional stress-state indicated a reverse ordering of the principal stresses as being the root cause of the poor hydraulic fracturing behaviour. However, careful consideration of the rock mechanics and a coherent pilot programme demonstrated the ability, under effective depletion conditions, to place economic and successful hydraulic fracturing treatments.
Rahim Bima Putra, Nur (National Oilwell Varco) | Leonanto, Raden (National Oilwell Varco) | Markandeya, Sri (National Oilwell Varco) | Ritamawan, Radianto (VICO Indonesia) | Sabri Saragih, Anggi Muhammad (VICO Indonesia)
When drilling wells for hydrocarbon extraction, completing a specific interval of the well in the fastest time possible is a key requirement. One of the main contributing factors for improved performance is the drill bit.
It is well known in the drilling industry that the stress state of the formation around the bit and drilled well is significantly lowered once penetrated by the bit. Conventional single diameter polycrystalline diamond compact (PDC) drill bits are not capable of taking advantage of this reduced effective rock strength.
Dual-diameter bits address the identified challenges through the use of elegant physical principles and offer an efficient, reliable means of drilling. The concentric, dual-diameter design lowers the effective rock strength encountered by the critical shoulder-to-gauge area of the bit's cutting structure.
The smaller pilot section of the bit design drills a pilot hole, which reduces the confinement and thus strength of the rock drilled by the larger reamer section. The reamer section of the bit is able to utilize the bedded pilot bit for stabilization to offset the greater forces associated with larger diameter drilling. The offset blade configuration of the bits also offers 360-degree contact the borehole and helps deliver a gun barrel hole quality.
This paper introduces the development of a unique, two-stage, dual-diameter profile, and polycrystalline diamond compact drill bit for an application in Indonesia. Typically, multiple drill bits are required to finish the section, which consists of abrasive sandstone with some layers of coal. The objective was to improve the drilling performance while also minimizing non-productive time (NPT) for a bit trip.
The paper provides and in-depth evaluation of the bit performance over several field trials. The first bit was run in a motor assembly and improved 14% rate of penetration (ROP) with exceptional dull condition. The drilling parameters indicated that the bit generated higher ROP with lower weight on bit (WOB) compared to other bit types. This performance convinced the operator to run the dual-diameter PDC bit in a more challenging field where its remarkable performance achieved field records. In comparison to the closest offset well, dual-diameter drill bits replaced three-bit runs with 56% longer intervals drilled and improved overall ROP by 41%. In addition, rig time was reduced by 5.3 days. The operator was extremely pleased with the bit performance and decided to use a dual-diameter PDC bit as the primary option to drill this section in every field.
Lilasari, Leonora (Schlumberger) | Paterson, Graeme (Schlumberger) | Armstrong, Philip (Schlumberger) | Juandi, Dedi (Schlumberger) | Septama, Erlangga (PT Pertamina EP) | Sukmatiawan, Adang (PT Pertamina EP) | Ardiansyah, Benny (PT Pertamina EP) | Handayani, Tri (PT Pertamina EP)
Seismic surveying is a vital part for the oil and gas exploration and is normally the primary method for structural interpretation. Unfortunately, the remote location and complex geology are most often degrading the seismic quality. In this circumstances, borehole seismic data can be acquired with multiple fixed offset position (MOVSP) to improve the structural image away from wellbore. On top of that, borehole dip data can be used to provide a high definition 3D near wellbore structural modeling. This paper presents a case study on the “BHG” development wells campaign, where these two techniques were integrated to provide an enhanced structural information.
The interpretation workflow of this study started with the structural interpretation of single well borehole dips. Shale dips which were deposited with a horizontal or near horizontal attitude provides the best input for structural analysis. In all “BHG” wells, the shale dips shows high magnitude and demonstrate dipping to different direction, indicating the structural deformation. In order to validate this single well interpretation, multi wells structural modeling was performed. The resulted model shows two structural features, anticline at the bottom which overlain by the monocline structure. The structure model was then integrated to the velocity model, ended up with a CDP image that correlated well with the dip information from the borehole image log, and allowed for a good model validation of the key events in the up-going wavefield, hence also validating the 3D near well structural modeling.
This technique has shown that it can greatly enhance the structural interpretation, velocity control and subsequent imaging, which provides invaluable to the oil and gas operator and can provide significant savings, HSE control and to avoid unexpected events during drilling, especially in development campaign where the reservoir structure has not been properly appraised.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 158716, "Renewal Plan: Efficient Strategy for Optimum Development in Mature Fields - A Success Story From Sanga-Sanga Assets, Indonesia," Andre Wijanarko, Bambang Ismanto, and Robhy Permana, VICO Indonesia, and Italo Pizzolante, Eni, prepared for the 2012 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 22-24 October. The paper has not been peer reviewed.
VICO Indonesia is the operator of the Sanga-Sanga production-sharing contract (PSC) in Indonesia. Against a backdrop of 46% annual base decline, VICO generated and implemented an integrated and aggressive work program called the Renewal Plan. This is an integrated approach between reservoir management and technology application. This plan proved to be an efficient example of better reservoir management for optimum development of mature assets.
The Sanga-Sanga acreage is located onshore in the Mahakam delta, East Kalimantan, Indonesia. The acreage is located within the Kutai basin, which is characterized by the Samarinda anticlinorium, with a series of highly prolific anticlines. Hydrocarbon accumulations are most often located within a series of mid-Miocene upper-delta and delta-plain sandstone reservoirs, and are principally characterized by fourway dip closure or two-way structural/ stratigraphic traps.
VICO Indonesia has been exploring and developing this PSC acreage actively since 1968. There are seven producing fields (Fig. 1): Badak, Nilam, Semberah, Mutiara, Beras, Pamaguan, and Lampake. These together produce 385 MMscf/D of gas and 14,500 B/D of liquids from 420 active wells, which have mixed wellbore completions (single, dual-selective, monobore, dual-monobore, and horizontal). The surface facilities supporting the production include four main production centers, 12 gathering stations, and more than 90 compressors.
After 40 years of production, these fields have now reached a fairly mature stage; most of the penetrated reservoirs/ tanks have been depleted from original pressures. Coupled with the annual production decline, this condition has resulted in significant challenges to delivering a continuous economic and efficient field-development strategy while maximizing field production.
VICO carried out a reserves-reassessment study—an integrated approach involving reservoir management and technology applications conducted by a multidisciplinary team. The seven components of the Renewal Plan are described in the following subsections.
Securing Base Production. Securing base production is one of the keys to achieving a production target. Well monitoring and surveillance are the primary methods by which base production is secured. Previously, VICO wells were monitored by frequent production tests, mostly depending on human surveillance.
In the Renewal Plan, automated real- time monitoring well surveillance of wellhead-pressure and flow-rate data on each well was implemented. This real- time wellhead surveillance (RTWHS) transmits the data from the wellsite to the VICO server; then, it is stored in a database. Operators and production engineers could monitor the behavior of the well in real time. This system has proved to minimize well downtime, leading to aggressive well reactivation.
This installation has also become standard for new wells. Currently, 90% of VICO’s active wells are equipped with RTWHS.
Microseismic hydraulic fracture monitoring uses state-of-the-art downhole seismic tools to record microseismicity from multi-staged hydraulic fracture stimulations in Coal Bed Methane (CBM) completions. This method uses an acoustic method to map in three dimensional space and time the geometry and propagation of fractures during a hydraulic fracture stimulation treatment. The technique has been used for some time in monitoring fracture stimulation in shales and other formations but has had limited use in coals for CBM production.
Microseismic monitoring of hydraulic fracture stimulations in coal seams presents significant challenges as the ductility of coal produces low intensity individual microseismic events which can be difficult to record. Using an offset well to record the microseismic events may result in some uncertainty due to varying degree of attenuation by the coal seam. Additionally, successful recording of fracture stimulations in CBM wells typically requires the monitoring well to be relatively close to the well being stimulated and this often prevents downhole monitoring being applied to these wells. [BJG1] A microseismic monitoring tool that can be placed in the treatment well during the fracture stimulation provides additional information and potentially improves the data quality. Furthermore, two monitoring tools which simultaneously record microseismic events in the in-well and offset wells provide independent data for comparison and increase the quality and confidence of spatial location data.
The Sanga-Sanga Block which is as a very large conventional gas producer in East Kalimantan is now growing as a potential CBM resource. The coal seams in Sanga-Sanga, East Kalimantan are contained in a complex formation of interbedded sandstone, siltstone, carbonaceous shale and coal and have been subject to initial attempts to stimulate the coals for CBM production by hydraulic fracturing.
This paper examines the operational challenges of the simultaneous use of in-well and offset well microseismic monitoring tools in the Sanga-Sanga coal in Indonesia and compares the techniques and overall results and makes recommendations and suggestions for future microseismic coal monitoring.