How is Kazakhstan expanding its oilfield activities?

At-a-Glance: Kazakhstan is expanding oilfield activity through brownfield debottlenecking at super-giant fields, sour gas handling/compression upgrades to sustain liquids, intensified drilling/IOR in mature onshore assets, and export-route diversification to de-risk CPC dependence.

Core levers: ramp of major expansions (notably at the two largest Caspian fields), new gas processing/compression, digital/ESP upgrades, and incremental Caspian shuttle volumes alongside CPC and the China pipeline.

I. Snapshot (2023–2024)

• I.1 Production:
  • Liquids: ~1.7–1.8 million bpd (crude + condensate), OPEC+ managed.
  • Associated gas: high H₂S; substantial reinjection at the largest sour oilfields to maintain plateau.
• I.2 Reserves:
  • Proved oil: ~30 billion bbl (estimated).
  • Giant fields: Tengiz, Kashagan, Karachaganak dominate reserves and liquids output.
• I.3 Evacuation capacity (estimated, nameplate vs. operable):
  • CPC pipeline to Black Sea: ~1.3–1.5 million bpd equivalent.
  • Atasu–Alashankou (to China): ~300–400 thousand bpd.
  • Caspian shuttle (Aktau–Baku) + onward pipelines: ~30–150 thousand bpd (scalable with tanker availability and terminal slots).
• I.4 Drilling/field activity:
  • Super-giants: multi-rig development/infill programs, artificial island drilling, high-pressure sour service completions, large-scale gas injection/compression.
  • Mature onshore basins (Mangystau, Aktobe): workovers, sidetracks, pattern realignment, polymer/surfactant pilots, ESP upgrades.

Relevant formulas

• Decline forecast (exponential):

  \( q(t)=q_i\,e^{-D t} \)

• Pipeline capacity conversion:

  \( \text{kbpd}=\dfrac{\text{Mtpa}\times 10^{6}\,\text{ton/yr}\times 7.33\,\text{bbl/ton}}{365\times 10^{3}} \)

• Reinjection fraction:

  \( f_{\text{reinj}}=\dfrac{V_{\text{reinj}}}{V_{\text{prod gas}}+V_{\text{reinj}}} \)

• Project NPV (simplified):

  \( \text{NPV}=\sum_{t=0}^{T}\dfrac{(P_{\text{oil}}\,q_{\text{oil}}-OPEX-CAPEX-TAX)_t}{(1+r)^t} \)

II. Strategic significance

• II.1 Market role:
  • Supply to Europe/Med: CPC-sourced barrels are critical to regional sour crude balance.
  • Portfolio balance: Growth hinges on sour megaprojects; mature onshore provides base but declining without IOR.
• II.2 Geopolitics and routing:
  • Landlocked exposure: Heavy reliance on CPC; diversification via Caspian shuttle and China line reduces single-route risk.
  • OPEC+ coordination: Production managed under quotas; short-term curtailments can mask underlying capacity growth.
• II.3 Cost and quality:
  • High H₂S/HPHT: Capex/opex premiums for sour service, corrosion control, sulfur handling; offset by very high field productivity.
  • Blending/differentials: CPC Blend trades at variable differentials to Brent due to route/geopolitical risk and assay.

III. Recent investment and project pipeline

• III.1 Super-giant brownfield expansions:
  • Tengiz: Future Growth/Wellhead Pressure Management adds ~200–260 thousand bpd incremental liquids at plateau via new sour gas injection and surface debottlenecking; phased start-up targeting mid-decade after delays.
  • Kashagan: Debottlenecking (+~60–80 thousand bpd) progressing; Phase 2A/2B staged concepts tied to gas disposal/processing capacity and sulfur logistics; extended-reach wells from artificial islands continue.
  • Karachaganak: Liquids maintenance through booster compression and gas handling (KPCU/expansion trains), sustaining condensate output despite rising GOR.
• III.2 Gas processing and compression to unlock oil:
  • Associated gas plants: New/expanded trains near Atyrau and Karabatan to capture sour gas, reduce flaring, and supply domestic demand, freeing reinjection optimization to maximize oil.
  • High-pressure compression: Additional stages for gas lift and reinjection improve reservoir pressure support and drawdown control.
• III.3 Mature field IOR and drilling intensification:
  • Waterflood optimization: Pattern realignment, conformance gels, and mobility control chemicals in Mangystau; incremental recovery factor uplift targeted at +3–8 percentage points.
  • Well interventions: Sidetracks in attic oil, ESP upgrades with condition-based monitoring, and sand control retrofits to extend runlife.
  • New horizontals: Thin-bed horizontals with geosteering to bypass water and contact remaining oil in clastic reservoirs.
• III.4 Digital and facilities upgrades:
  • Digital oilfield: SCADA expansion, fiber-optic DAS/DTS in key injectors, predictive ESP analytics.
  • Corrosion/HSE: Duplex/CRA metallurgy, improved sour service standards, sulfur block/rail logistics enhancements.
• III.5 Export diversification investments:
  • CPC debottlenecking: Incremental pumping and terminal upgrades to stabilize throughput and reduce weather downtime.
  • Caspian route scale-up: Additional tankage at Aktau, chartering of shuttle tankers, and tie-in to onward pipelines westward.
  • China corridor: Flow assurance and batching improvements to lift utilization toward design rates as market pull warrants.

Engineering note (oil unlock via gas handling)

For sour reservoirs where reinjection sustains pressure, liquids plateau is constrained by gas handling. Incremental oil ?q_oil scales with additional gas processing/injection ?Q_gas and reservoir gas-oil coupling:

\( \Delta q_{\text{oil}} \approx \alpha \,\Delta Q_{\text{gas}}\quad \) with \( \alpha \) determined by injectivity, MMP, and reservoir connectivity; facility trains are thus sized to maximize \( \alpha \) under quota and offtake limits.

IV. Fiscal and regulatory regime highlights

• IV.1 Contracting frameworks:
  • PSAs for legacy giants with stability clauses; newer blocks under tax-royalty regime (Subsoil and Subsoil Use Code).
  • State participation and NOC pre-emption on strategic assets and midstream links.
• IV.2 Taxation (indicative):
  • Mineral Extraction Tax (MET) on volumes, sliding with price/quality.
  • Excess Profits Tax (EPT) on projects above threshold profitability.
  • Corporate income tax and export customs duty on crude (variable, price-indexed); VAT exemptions on certain imports for priority projects.
• IV.3 Local content and labor:
  • Local content targets in goods/works/services; reporting requirements and preferential procurement.
  • Work permit quotas for expatriates; skill transfer and training obligations.
• IV.4 HSE and emissions:
  • Flaring limits with penalties; mandatory gas utilization plans for new developments.
  • Sulfur management standards for sour fields; environmental fees and monitoring under national ETS framework.
• IV.5 Market management:
  • OPEC+ compliance can temporarily cap output despite new capacity.
  • Domestic supply obligations for oil products/gas can influence operating strategies at the margin.

V. Near-term outlook (1–5 years)

• V.1 Supply trajectory:
  • Upside: Tengiz FGP/WPMP ramp plus Kashagan debottlenecking could lift national liquids by ~200–300 thousand bpd versus recent averages when unconstrained.
  • Base decline: Mature onshore declines at ~5–10%/y without IOR; targeted interventions aim to halve effective decline.
  • OPEC+ constraint: Realized output may lag installed capacity depending on quota path.
• V.2 Evacuation and pricing:
  • Routing mix: CPC remains dominant; Caspian shuttle/China corridor serve as flex outlets to manage outages and optimize netbacks.
  • Differentials: CPC Blend discount to Brent likely volatile (indicatively Brent -$2 to -$6/bbl), improving with reliability and quality management.
• V.3 Cost and execution:
  • Inflation/complexity: HPHT/sour service, labor constraints, and logistics keep capex elevated; modularization and local fabrication mitigate schedule risk.
  • Power: Grid constraints in Atyrau/Mangystau drive captive power and waste-heat recovery additions.
• V.4 ESG and gas balance:
  • Flaring reduction via new gas plants supports regulatory compliance and social license.
  • Domestic gas demand growth competes with reinjection needs; optimal split is a key planning variable.

Forecasting aid

Aggregate liquids outlook blends megaproject ramps with mature-field decline:

\( q_{\text{KZ}}(t)=\underbrace{\sum_{i \in \text{mega}} q_{i}(t)}_{\text{expansions/debottlenecks}}+\underbrace{\sum_{j \in \text{mature}} q_{j,0}\,e^{-D_j t}}_{\text{managed decline}} \)

VI. Key risks and opportunities

• VI.1 Risks:
  • Route concentration: CPC disruptions (weather, legal, or geopolitical) can curtail exports.
  • Project execution: Cost overruns and schedule slippage on HPHT/sour expansions.
  • Reservoir/flow assurance: H₂S corrosion, scaling, sulfur handling, winter operations in the Caspian.
  • Policy: Quota changes (OPEC+), adjustments in export duty/MET, or local content enforcement affecting procurement.
  • Energy/power: Grid instability limiting compressor/ESP uptime.
• VI.2 Opportunities:
  • Debottlenecking: Additional gas handling/compression trains can directly translate to higher liquids.
  • IOR/EOR scaling: Polymer floods and surfactant-assisted waterfloods in clastics; conformance control in carbonates.
  • Digital reliability: Predictive maintenance for ESPs and compressors improves runlife and reduces deferred production.
  • Export optionality: Incremental Caspian shuttle capacity and optimized batching on the China line improve netbacks and resilience.
  • Electrification/WHR: Waste-heat recovery and renewables-hybrid power lower opex and emissions fees.