TX 75083-3836, U.S.A., fax 01-972-952-9435. ProposalSeveral horizontal wells have been drilled in different sandstone formations in Sumatra. These formations have a typical permeability of 100 to 500 md, a low bottomhole pressure (BHP) of 450 to 750 psi, and a bottomhole temperature (BHT) of approximately 200ºF. The wells are completed with perforated liner. The objective of the horizontal drilling program was to increase oil recovery in low-permeability estuarine reservoirs. Some of the drilled horizontal wells did not perform to expectations and an intensive study was undertaken to identify completion and stimulation opportunities to increase production.During this study, all aspects of the initial completions were examined and redesigned.1. The drill-in mud was reformulated to reduce the amount of polymer and increase the use of fine calcium carbonate to decrease lost circulation during drilling and simplify the removal of filter cake during initial completion. 2. Core tests were performed to identify the optimum fluid formulation, which dissolves the remaining filter cake but does not destroy the formation's natural permeability. 3. A new way of removing the filter cake after completing the well was introduced using oxidizer technology. 4. A new, true fluidic oscillator was used to remove nearwellbore skin (in conjunction with an improved acid system) for wells that have been producing for several months or years.The paper presents several case histories to discuss how completion and stimulation problems were systematically evaluated resulting in increased horizontal well production.

Summary Several horizontal wells have been drilled in different sandstone formations in Sumatra. These formations have a typical permeability of 100 to 500 md, a low bottomhole pressure (BHP) of 450 to 750 psi, and a bottomhole temperature (BHT) of approximately 200ºF. The wells are completed with a perforated liner. The objective of the horizontal-drilling program was to increase oil recovery in low-permeability estuarine reservoirs. Some of the drilled horizontal wells did not perform to expectations, and an intensive study was undertaken to identify completion and stimulation opportunities to increase production. During this study, all aspects of the initial completions were examined and redesigned. The drill-in mud was reformulated to reduce the amount of polymer and increase the use of fine calcium carbonate to decrease lost circulation during drilling and to simplify the removal of filter cake during initial completion. Core tests were performed to identify the optimum fluid formulation, which dissolves the remaining filter cake but does not destroy the formation's natural permeability. A new way of removing the filter cake after completing the well was introduced using oxidizer technology. A new, true-fluidic oscillator (TFO) was used to remove near-wellbore skin (in conjunction with an improved acid system) for wells that have been producing for several months or years. The paper presents several case histories to discuss how completion and stimulation problems were systematically evaluated resulting in increased horizontal-well production. Introduction Oil- and gas-producing companies have been greatly interested in horizontal wells because their increased inflow area provides the potential to produce more oil and gas compared with vertical wells. The history of horizontal wells goes back as far as 1947.1 In the last two decades, the industry intensified efforts in exploring the potential of horizontal wells and overcoming many challenges that are particular to this type of completion. The advantages associated with horizontal wells have been identified by several authors and can be summarized as follows 2-4 :• Maximizing reservoir exposure.• Targeting multiple zones.• Exploiting thin pay zones.• Reducing drawdowns to minimize premature water and gas coning.• Improving production rates and increasing recoverable reserves. The three types of horizontal-well completions are openhole completions (with and without perforated or slotted liner), openhole completions with screens in place (with or without gravel pack), and cased-hole completions (also called stimulation completions).5 The decision of which completion to use depends on the specific reservoir characteristics.3 Cased-hole completions offer the advantage of simpler workovers and the option of specifically designed stimulation treatments. Furthermore, perforating the liner after cementing it in place can ensure that mud filtrate or invasion is bypassed. Consequently, these completions are more expensive and include challenges, such as obtaining an efficient cement placement along the entire interval for effective isolation and designing an effective perforating strategy. If sand control is an issue, then screens and prepacked liners are commonly used to avoid sand production (with or without gravel packing). Challenges in this case are associated with avoiding plugging the screen with mud and drilling solids and ensuring that the entire interval is producing to avoid hot spots, which could introduce local erosion of the screen.6 If the zone of interest is a consolidated formation that is not susceptible to formation collapse, then an openhole, or barefoot, completion becomes attractive. The disadvantages of a barefoot completion include the limited ability to perform workovers in certain areas in case water or gas breakthrough is observed. This becomes a significant problem in sandstone formations in which the high frictional force between the interface of the formation and coiled tubing does not allow coiled tubing to enter to a great depth. This challenge can be overcome by deploying slotted or preperforated liners plus external casing packers (ECPs). Optimum production results for openhole completions, with or without a preperforated liner, can be achieved by using a specifically designed drill-in fluid (DIF) then effectively removing the mud filter cake formed by the DIF. Both areas have been studied and discussed by Morgentaler et al.,7 Browne and Smith,8 and others. These studies found that 100% effective removal of the filter cake in horizontal openhole wells is not necessary because of the large inflow area. In fact, Browne and Smith concluded that if the permeability reduction is less than 70%, then the productivity of the wells does not fall significantly. Furthermore, they identified that the permeability of the mud filter cake has only to be increased to 0.1 md from approximately 10–5 to 10–8 md to achieve the same productivity as complete removal of the filter cake. Thus, 100% removal of the filter cake may not be a necessity and the optimum design should take this fact into account to identify a mud-removal design that meets the economic feasibility of the well. For horizontal wells that have been produced for a period of time and experience a production decline, the challenge is not to remove the mud filter cake but to identify where the damage is coming from and how to remove it. Common causes for production decline include depletion, scale buildup, paraffin and asphaltene dropouts, fines migration, and others. Thus, for older wells, the most important issue is identifying the damage and designing a treatment accordingly. For each particular well, an engineered solution should be designed involving problem identification, fluid-compatibility studies and core analysis, completion design (e.g., placement9 and unloading procedures), and more.

The proven and most suitable stimulation technology to increase production in a tight sandstone formation is hydraulic fracturing. The hydraulic fracturing treatment will create a fracture and then keep it open by proppant, hence a conductive path allowing more oil and gas to be produced. Hydraulic fracturing operations in an offshore environment are sometimes considered as a costly solution and non-economic. An alternative economic solution, Fracture Assisted Sandstone Acidizing (FASSA), was evaluated. Sandstone acidizing is a method to increase oil production, by injection of compatible acid system at matrix rate, below the formation fracture gradient. This stimulation method is most suitable to remove near wellbore damage in medium-high formation permeability. To improve the effectiveness of the acid treatment in tight sandstone reservoir, a hydraulic fracture was created prior to the sandstone acidizing. Besides removing the near wellbore damage, the acid is expected to react with fracture face in sandstone and create a conductive path for oil to flow. Four successful jobs have been performed to date. This paper will describe planning, process, acid treatment selection, operation summary, and evaluation of success or failure of the treatment. In the future we also propose to perform similar treatments for a tight reservoir without having to pull out the existing completion.

Offshore North West Java (ONWJ) field has been producing since 1971 with multi-stacked layers, solution gas to weak water drive mechanism, most of wells are completed with dual strings and gas-lifted. This condition compromise a relatively shallow top packer placement. In some cases, abandonment pressure has been reached as characterized by low static liquid level below deepest gas-lift mandrel. Apart from that, tubing integrity is becoming important issue as fields are maturing. Less operational complexity for the installation of siphon string or velocity string to tackle the two challenges above and better economic returns make it a better option compared to recompletion. The applied strings are from 1.75″ QT-900 coiled tubing, installed with various configurations of packer, gas-lift mandrel, and length depending upon wellbore completion, artificial-lift concern and well integrity requirement. Siphon string has been installed in 6 strings; whereby 3 strings with tubing integrity issue (well A, B and C), 3 strings with liquid level below deepest gas-lift injection mandrel (W, Y and Z). After installation, well A and B were flowing for 2 years before they were finally shut-in due to leak below the siphon string assembly. Well C had flowed for another 6 years before it was shut-in. Well X has been flowing since the inception of siphon string in 2006 until this paper is written, well Y has flowed for 8 years and well Z has been flowing for 1 year. An increase of 0.5% – 2% of recovery factors for these wells has created opportunity for other similar wells to continue or increase production. The first part of the paper will describe on the candidate selection and well configuration, the second part of the part will cover the installation procedures, challenges and lessons learnt. Finally, production results comparison from pre and post installation is presented.

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