Total E&P Indonesie (TEPI) is the main gas producer in Indonesia which produces around 1900 MMscf/d of gas. One of the challenges is to maintain its production plateau under liquid loading issue. Almost half of TEPI gas production comes from liquid-loaded wells, representing 85% of total producing wells in the affiliate. Up until recently, dewatering activity in TEPI is only performed by means of regular offloads; involving substantial means. These operations present specific risks not only for safety and assets but also for environment by flaring of gas through testing barge. A cross functional team has been established to find out innovative solution based on the "Foam Assisted Lift" (FAL) principle and enabling to keep existing DHSV in the well completion. The FAL principle consists in offloading the wells by creating foam down-hole through continuous injection of surfactant to help liquid lifting and gas breakthrough. This paper describes Capillary String Injection System that can be fitted into existing wells, using existing DHSV control line for surfactant injection while keeping its primary safety function as a fail-safe device. The installation equipment includes a modified wireline-retrievable surface-controlled sub-surface safety valve (WR-SCSSV) with capillary tubing attached below it. Injection operates via existing control line of the safety valve to inject chemicals, does not require any further wellhead modification. In addition, this system fits perfectly with the context of mature field; simple, cost-effective, safe and easy to handle.

Well N-1 in Mahakam Sisi Nubi field, East Kalimantan, had a problem with water and condensate production up to 11,000 BLPD which instantly rendered the production facility overwhelmed despite the high 34 MMSCD gas rate. To solve this, reservoir production profiling using production logging tool was first carried out. Selection of existing zone isolation method was then compared, yet none satisfies the challenges in this well due to restriction and cost issues. A relatively new technology, High Expansion (HEX) Straddle Packer, was introduced as another alternative. A series of engineering design and followed by operation design was then carried out to solve the well problem safely. A dummy tool run with 2.875" OD and 30ft of length passed through the restriction safely. Caliper logging observes reduction in tubing ID from 3.9" to 3.0". Temperature of the borehole reached 115 deg C at 3417 mBRT of this well. The two water producing zones were next to each other with a total top reservoir to bottom reservoir length of 11 m. With these values, a custom 2.7" straddle packer was built and tested to required temperature and passed. Production simulation with 0.7" ID, indicated the well could still flow over its critical flow regime. After installation, the well flows with 11 MMSCFD of gas with ~1800 BLPD liquid produced, a 83% reduction over previous liquid flowrate. Despite the well flows only 30% from initial gas rate, this well can now flow at an acceptable liquid rate. The successful installation of the first HEX Straddle expands the portfolio of mechanical water shut off methods in Mahakam and in Indonesia as this was the first HEX Straddle installed in Indonesia. Further study and replications are needed, yet this method can be a viable alternative if other has failed for wells with similar problems.

Nowadays oil and gas industry are encouraging the independents and majors to take a fresh look at the technology and concepts required to develop marginal shallow water fields using a minimal platform approach. Innovation on well intervention means (lighter, smaller and less footprint) that fit for Offshore Minimalist Platform (OMP) is needed, including optimizing time and cost during well intervention activities in OMP. To achieve the objectives, well intervention innovation and technology are the main focuses. Intervention activities commonly done on campaign basis with several units (slickline, wireline, coiled tubing, testing) shall be integrated in a safe manner. The approach of integration shall signify these points:Identifying potential jobs in OMP to be done by well intervention methodsIdentifying necessary well intervention means and methods to support the jobs (combo unit, micro coil, hazardous zone redefinition, remote operation)Creating project planning and schedulingPerforming site visit and risk assessmentImplementation and operational executionEvaluation of overall project execution result The following results were obtained after the integration performed:No major safety issues during operationExemplary method and risk assessment for well intervention activities which can be applied for next campaignsTrials on well intervention new units and method (combo unit, micro coil, hazardous zone redefinition, remote operation), were safely performed with some optimization100% success ratio60% on supply boat arrangement35% efficiency in N2 consumption for CT operation45% efficiency in diesel consumption20% - 40% efficiency in Rig Up Time28% less in Job Cost compared to conventional unit These innovations are proven as reliable method to answer OMP challenges with main advantages on footprint and cost optimization. Through this paper, we would like to share lucrative well intervention breakthrough and innovation in OMP with measurable milestones.

We present perforating on wireline with dynamic underbalance (DUB) to simultaneously maximize productivity and minimize gunshock. We focus on perforating on wireline with DUB because, when compared with other approaches, perforating with DUB is probably the best method to deliver lower tunnel plugging and lower formation rock damage, with lower risk of tool damage due to gunshock or guns blown uphole. Specifically, we present two important aspects of perforating on wireline using DUB: prediction of wellbore dynamics to assess perforation tunnel and formation cleanup and gunshock prediction to assess the risk of tool damage. We present the latest models used to evaluate perforating jobs for well productivity and for operational risks.It is well known that the DUB produced when perforating with the right gun system can remove formation rock damage and tunnel plugging produced by shape charges. What is not so well known is how much DUB (amplitude and duration) is necessary, and how to predict how much DUB will be generated by a gun system. To achieve formation tunnel cleanup, we need a DUB of large amplitude but short duration to remove perforating rock damage and plugging while minimizing gunshock loads. In the pre-job design, we simulate/predict the transient fluid pressure waves in the wellbore and formation rock to predict formation rock damage cleanup and also the associated gunshock loads. DUB amplitude and duration depend on job parameters that can be adjusted, such as type and size of guns, loading of standard perforating charges and DUB charges, and placement of packers, if present. Important physics included in the model are: gun filling, wellbore pressure waves, transient reservoir fluid flow, and the dynamics of all relevant solid components (cable, shock absorbers, tools, and guns).The reliability of the DUB prediction model is demonstrated by comparing downhole fast-gauge pressure data with the corresponding simulated values. When the reservoir properties are well known, the predicted DUB amplitude and duration are very close to the field data values, typically within 15% or less. The reliability of the gunshock loads is demonstrated with residual shock absorber deformation and cable tension logs. We also demonstrate how gunshock simulations have been useful to explain equipment failures due to gunshock loads.Reliable predictions of wellbore dynamics, transient reservoir flow, and gunshock loads enable operators to select perforating equipment capable of removing perforating formation damage and reduce the risk of unexpected release of tools and guns due to dynamic loads, thereby minimizing the probability of nonproductive time and fishing operations.

This paper will demonstrate technology to do downhole interior reconstruction in an older well design to create larger tool access using wireline technology. The intent is to document the applied technology and the value creation.The methods described were actual field operations demonstrating the successful application of the technology in a mature field. This paper will describe the history, background and challenges of a well in this mature field and the subsequent application of alternate technology to overcome those challenges and maintain the asset as a viable, producing well.Due to the availability of downhole tools and services to solve an immediate problem in a well, the need to reconstruct the existing wellbore interior to create larger access for example, becomes inevitable in many cases. Such was the case on offshore wells in Indonesia where the inner diameter size of the downhole accessories forbid tools to reach the lower targeted depth.Following the success of the first nipple milling in the world at an Operator's field in Indonesia in 2009, another 12 wells had applied the same intervention technique at one field location and many other wells in various part of the world. The advantage of wireline nipple milling includes level of precision in milling, new smooth finishing of treated downhole accessories or completions, minimum cuttings left downhole, minimum volume of liquid required, small footprint required during operation and speed of milling operation that could be less than 2 hours even in small restriction such as 2.6 inch inner diameter.This paper presents the up to date achievements, case histories, challenges, best practices and technical aspects of the aforementioned milling system as well as similar challenges can be solved using similar technique.